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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, 1997 Commission File Number 0-18886
HS RESOURCES, INC.
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(Exact name of Registrant as specified in its charter)
DELAWARE 94-3036864
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
ONE MARITIME PLAZA, FIFTEENTH FLOOR
SAN FRANCISCO, CA 94111
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(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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Title of each class of stock
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Common Stock - $.001 par value New York Stock Exchange
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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
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy information statements
incorporated by reference in Part III of the Form 10-K or any amendment to this
Form 10-K. [X]
Aggregate market value of Common Stock held by non-affiliates of the registrant
as of the close of business at February 28, 1998: $241,268,664.
Number of shares of Common Stock outstanding as of the close of business on
February 28, 1998: 18,423,987 after deducting 230,558 shares in treasury.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement of HS Resources, Inc. to be dated on or before
April 30, 1998, are incorporated by reference into Part III. (A definitive
proxy statement will be filed with the Commission within the prescribed
period.)
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TABLE OF CONTENTS
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Part I.
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Item 3. Legal Proceedings and Environmental Issues . . . . . . . . . . . . . 20
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . 21
Part II.
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . 22
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . 23
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . . . . . . 24
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . 42
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . . . . . . . 74
Part III.
Items 10-13. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74
Part IV.
Item 14. Exhibits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75
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PART I
Item 1. BUSINESS
THE COMPANY
HS Resources, Inc. ("HSR" or the "Company") is a leading U.S. independent energy
company engaged in the acquisition, development, exploitation, exploration,
production and marketing of oil and gas. In 1997 HSR established Company records
in production and reserves, both on an absolute and a per-share basis.
Production for the year was 2.4 million barrels of oil and 41 billion cubic feet
of gas, or 9.3 million barrels of oil equivalent ("Boe"), an increase of 21%
over 1996. Year end proved reserves were 45.4 million barrels of oil and 880
billion cubic feet of gas, or 192 million Boe, an increase of 35% over the prior
year. Reserves per share were 10.9 Boe, an increase of 12% over the prior year,
and production per share was 0.53 Boe, compared to 0.52 Boe in 1996.
In December 1997, HSR acquired from Amoco Production Company ("Amoco") all of
Amoco's producing and non-producing properties (the "Amoco Properties") in the
Wattenberg Field area of the Denver-Julesburg ("D-J") Basin (the "Amoco
Acquisition"). This strategic acquisition positions HSR as the leading producer
in the D-J Basin with estimated daily production at year end of more than 25.1
MBoe. The Amoco Properties have substantial geographic and geological overlap
with HSR's existing D-J Basin assets and provide the Company with more than
2,100 low-risk, high-return projects, many of which can be undertaken with a
significantly lower capital investment than that which would have been required
for development by HSR or Amoco independently. The Amoco Properties present the
Company with almost $500 million of development and exploitation capital
expenditure opportunities that greatly enhance its reserve and production growth
potential.
The Company has created a diversified asset base with activities in four core
geographic areas: the D-J Basin, the Mid-Continent, the onshore area of the
Texas-Louisiana Gulf Coast and the Northern Rocky Mountains. The Company's
Mid-Continent presence, which is focused in the Anadarko and Arkoma Basins, was
established through its 1996 merger (the "Merger") with Tide West Oil Company
("Tide West"). This presence has been further enhanced by exploration,
exploitation and development activities. The Company has current daily
production from its Mid-Continent properties of 32,689 Mcf of gas and 1,016 Bbl
of oil. In the Gulf Coast, the Company has assembled control of approximately
335,000 gross undeveloped acres and is conducting an active exploration and
drilling program. The Company has acquired more than 530 square miles of 3-D
seismic data. In the Northern Rocky Mountains, the Company has 593,000 gross
undeveloped acres, primarily in the Williston and Greater Green River Basins.
At year end, HSR had an inventory of over 4,100 development, exploitation and
exploration opportunities, along with over 1.2 million gross undeveloped acres.
The opportunities include development, exploitation, exploration and infill
drilling, recompletion, wellbore deepening and refracturing projects. The
Company believes that each of its four core geographic areas presents
opportunities for growth in proved reserves and production.
At December 31, 1997, the Company reported proved reserves of 192 MMBoe, with
estimated pre-tax present value (discounted at 10%) of $822.5 million. Gas
constituted approximately 76% of the Company's reserves and approximately 67% of
the Company's reserves were classified as
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developed. At December 31, 1997, the Company operated approximately 62% of its
5,375 wells. During the twelve months ended December 31, 1997 the Company
generated net cash flow (defined as net income, plus depreciation, depletion and
amortization, deferred taxes and extraordinary items) of $70.7 million, with
average production for the quarter ended December 31, 1997 of 26,277 Boe per
day.
HSR is a Delaware corporation organized in 1987. Its principal subsidiaries are
Orion Acquisition, Inc. ("Orion"), which holds the assets acquired in the Basin
Acquisition, HSRTW, Inc. ("HSRTW"), which holds the assets acquired through the
Merger, and HS Energy Services, Inc. ("HSES"), the Company's gas marketing,
trading and transportation subsidiary. The Company's principal executive offices
are located at One Maritime Plaza, Fifteenth Floor, San Francisco, California
94111 and its telephone number at such address is (415) 433-5795.
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BUSINESS STRATEGY
HSR's objective is to maximize shareholder value through aggressive growth in
its oil and gas reserves and production. To achieve these objectives, the
Company pursues a strategy of (i) consolidation in core areas, (ii) exploitation
of its property base, (iii) exploration in focused prospective areas, and (iv)
application of advanced technology.
o Consolidation. Near the end of 1997 HSR acquired Amoco's D-J Basin
properties, capping an effort that spanned several years. For HSR,
the compelling reason for the acquisition was the substantial
reserves that could be unlocked by combining the Amoco properties
with its own. For example, in many instances HSR owns the right to
produce from formations which are "behind pipe" in an Amoco
producing well. Bringing these reserves into production by
recompleting an existing well generates substantially better
economics than can be achieved by drilling a new well. In other
instances, Amoco owned the right to produce from formations located
deeper than horizons from which HSR was already producing.
Deepening an existing well is substantially more economic than
drilling a new well. Without these efficiencies many reserves were
economically "stranded" because drilling a new well could not be
justified. The re-aggregation of reserves and value created by the
Amoco Acquisition gives the Company a substantial inventory of
projects with little operational risk, but with attractive rates of
return.
o Exploitation. HSR has more than 4,100 low risk exploitation
projects in its inventory, including such activities as
recompleting new formations in existing wells, re-stimulating
currently producing zones, deepening existing wells to new
formations, and drilling infill and other development locations.
Located primarily in the D-J Basin and the Mid-Continent region,
these projects show attractive rates of return. Based on its
planned exploitation program alone, without taking into
consideration exploration success, the Company believes it should
be able to sustain substantial production growth for the next five
years. The Company anticipates a total 1998 capital budget of
$90-$100 million, with $60-$75 million allocated to the D-J Basin
and $15-$20 million allocated to the Mid-Continent for low risk
exploitation projects. In the D-J Basin the Company plans to
undertake more than 550 exploitation activities in 1998, drilling
90 new wells, including 55 J-Sand infills, 436 recompletions and
refracs and 40 Dakota deepenings. In the Mid-Continent the Company
plans to drill 73 wells and recomplete 12. In addition, to
replenish its inventory the Company has several ongoing initiatives
including further reservoir analyses in the D-J Basin and active
exploitation teams focused on the Arkoma and Anadarko Basins in the
Mid-Continent.
o Exploration. HSR has 22 high-potential exploration projects in
various stages of maturity and development. Eighteen active
projects are located in the Gulf Coast region, where the Company
has shot more than 530 square miles of 3-D seismic and has
identified 110 prospects and leads. Initial geological and
geophysical work is nearing completion on several of the projects,
and the Company expects to spend net capital of approximately $15
to $20 million in the Gulf Coast during 1998, drilling an
anticipated 21 wells, shooting 285 square miles of 3-D seismic and
acquiring leasehold and option acreage.
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HSR also has active exploration projects in the Mid-Continent
region, the D-J Basin and in the Northern Rockies. The principal
focus of the Mid-Continent District will be the 3-D program on the
Company's Bivins Ranch field. 3-D driven exploration will continue
in the D-J Basin. In addition, the Company's large acreage position
in the Northern Rockies continues to yield significant
opportunities. Joint programs with industry partners are under way
on the Pinedale anticline and in the Williston Basin, and the
Company has two high-potential projects in the Green River Basin in
Wyoming.
o Technology. HSR's highest visibility technology is the use of 3-D
seismic in its exploration programs. Use of this technology is
intended to reduce exploratory risk and enhance economic results.
The Company's 3-D seismic inventory includes 985 square miles of
data coverage in hand and interpreted, with almost 400 square miles
of additional seismic planned and under program design. Other
technologies applied by the Company include reservoir simulators,
directional drilling techniques and fully integrated digital
databases, each of which aids in the efficient development of
hydrocarbons. In addition, proprietary systems are used to enhance
operating efficiencies by identifying and high-grading wells for
field optimization, further engineering study and field remedial
work. Other proprietary systems are planned or under development,
including one intended to apply "artificial intelligence" methods
to schedule field maintenance activity.
RECENT DEVELOPMENTS
Acquisitions and Divestitures
The Company is committed to strategic rationalization of assets in each of its
core areas both through advantageous acquisitions and non-core property
divestitures. The Company has aggressively pursued these objectives, resulting
in the Amoco Acquisition, three significant dispositions, several smaller
tactical acquisitions and the screening of numerous acquisition opportunities.
During 1997, the Company sold non-strategic, non-core properties (including the
assets transferred to Amoco as part of the Amoco Acquisition) in three
transactions for an aggregate of $58.6 million.
Amoco Acquisition
The Amoco Acquisition provides (i) a significant increase in oil and gas
production (adding net daily production at year end of 8,353 Boe from the Amoco
Properties), (ii) an expected reduction in per unit operating costs due in part
to increased production per wellbore following development and exploitation
activities, (iii) an anticipated increase in D-J Basin capital spending to
$60-75 million for 1998 to pursue additional infill, recompletion, deepening,
refrac and drilling projects, (iv) an expected decrease in per unit general and
administrative expense and (v) an increase of approximately $2.5 million per
year net to the Company in the monetization of Section 29 income tax credits.
The increase in production from the Amoco Properties is partially offset by the
estimated daily production at year end of 1,252 Boe from the properties
transferred to Amoco.
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MARKETING AND TRADING
Gas Marketing and Trading
Since the beginning of 1996, the market for the Company's D-J Basin gas has
strengthened substantially due to several factors. First, excess supply from
Wyoming 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 gas sold to the Colorado Front Range market, resulting in a transportation
cost advantage for D-J Basin producers of approximately $0.40 per MMBtu. Third,
the supply of D-J Basin gas has declined over the last two years due to the
combination of reduced drilling in the D-J Basin and natural production
declines. The Company's transportation cost advantage in the D-J Basin could be
reduced as a result of certain proposed pipeline projects. For further
discussion, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Gas Price Considerations." The market for the Company's
Mid-Continent gas remains stable and flexible with access to a number of
interstate pipelines.
Oil Marketing and Trading
Substantially all of the Company's oil production is sold under contracts having
terms of one year or less based on prices which are reflective of world crude
oil prices adjusted for geographic and quality differentials. Oil is sold to
many different purchasers at generally market sensitive rates. The most
significant purchaser of the Company's oil production currently is Amoco, which
purchases 39% of the Company's oil production. The Company believes that there
are sufficient crude oil purchasers in the market so that the loss of any one
particular customer would not have an adverse effect on the Company.
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 for production from tight gas sand reservoirs. That value would
otherwise be lost to the Company because of its tax position. In each
transaction, the Company or its subsidiary conveys substantially all of the
working interest in credit-qualified properties to a limited liability company
owned by one or more large financial institutions. The Company retains a 100%
production payment in the properties and an option to reacquire the properties.
The effect of the transactions is such that the Company receives
production-related cash flow as if it were the working interest owner, and the
investor receives tax credits. The investor makes an initial payment to the
Company, and makes periodic payments that vary depending on the volume of
credit-qualified gas produced. The transactions are structured in accordance
with private letter rulings issued by the Internal Revenue Service ("IRS") to
third parties. In some cases, the investors obtain private letter rulings which
specifically cover the Company's transactions. Through these transactions, the
Company has recognized approximately $4.4 million and $2.7 million of other gas
revenues associated with the tax credits during the years ended December 31,
1997 and 1996, respectively. The Company expects to receive in excess of $29
million of tax credits for the period 1998 through 2002.
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Although the Company believes the possibility is remote, the IRS could decide to
challenge the validity of the transactions that are not directly protected by a
letter ruling.
COMPETITION
The oil and gas industry is highly competitive. The Company competes in the
areas of property acquisitions and the development, production and marketing of
oil and gas with major oil companies, other independent oil and gas concerns and
individual producers and operators. The Company also competes with major and
independent oil and gas concerns in recruiting and retaining qualified
employees. Many of these competitors have substantially greater financial and
other resources than the Company.
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 Gas. Historically, the
transportation and sale for resale of 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
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 removing, as of January 1, 1993,
all remaining federal price controls from gas sold in "first sales." The FERC's
jurisdiction over 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 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 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 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,
including 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 gas.
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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.
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 it 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 a
third-party 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, 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. Presently, the State of Colorado Oil and Gas
Commission is considering adopting stricter policies for the enforcement of
environmental rules and regulations. 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, regulations and policies
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 EPA.
TITLE TO PROPERTIES
A title opinion generally 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 typically thorough but less rigorous
than that conducted prior to drilling, consistent with standard industry
practice.
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OPERATIONAL HAZARDS AND INSURANCE
The Company's operations are subject to the usual hazards incident to the
drilling and production of oil and gas, such as blowouts, cratering, explosions,
uncontrollable flows of oil, 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. The
Company believes its insurance coverage is reasonable and prudent for the types
of risks it expects to encounter. The Company's insurance does not cover every
potential risk associated with the drilling, production, storage and
transportation of oil and gas and, while certain environmental coverage is
provided, coverage is not obtainable for all types of environmental hazards. The
occurrence of a significant adverse event, the risks of which are not fully
covered by insurance, could have a material adverse effect on 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, 1997, the Company had 260 employees, with 30 located in San
Francisco, California, 74 in Denver, Colorado, 68 in Tulsa, Oklahoma, 86 in
Evans, Colorado and 2 in Houston, Texas. 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
1997, the Company entered into a new six year lease, with options, in Denver,
Colorado which covers 52,749 square feet at an average monthly rental of
$59,098. In August 1997, the Company entered into a lease agreement for 5,362
square feet of office space in Houston, Texas, at a monthly cost of $4,692,
expiring April 30, 2000. The Company leases office space in Tulsa, Oklahoma
which covers 24,581 square feet at a monthly rental of $29,768 per month
expiring December 31, 2001. 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 $6,605 per month expiring April 9, 2002.
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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, 1997.
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RESERVES 3-D
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TOTAL OIL PERCENT OF NET GROSS DATA
GROSS PERCENT OIL GAS EQUIVALENT TOTAL PRODUCTION UNDEVELOPED (SQUARE
WELLS OPERATED (MBBL) (MMCF) (MBOE) RESERVES (BOE/DAY)(1) ACREAGE(2) MILES)
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D-J Basin
Wattenberg Field Area 3,891 62 38,287 671,670 150,232 78 13,226 101,803 --
Greater D-J Basin 495 92 2,130 37,852 8,439 4 4,965 173,333 84
Mid-Continent
Anadarko Basin 405 37 1,581 48,055 9,590 5 3,315 1,520 13
Arkoma Basin 384 56 47 62,646 10,488 6 1,866 6,052 --
Southern Oklahoma 90 66 2,578 28,366 7,305 4 1,346 720 --
New Mexico/Texas 75 51 537 24,740 4,660 3 858 25,570 24
Gulf Coast 9 22 92 3,054 601 -- 675 334,575 531
Northern Rocky Mountains 26 96 106 3,471 685 -- 26 593,345 333
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Total: 5,375 62 45,358 879,854 192,000 100 26,277 1,236,918 985
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(1) Calculated for the quarter ended December 31, 1997.
(2) Includes leasehold, option and seismic rights.
Denver-Julesburg Basin
The D-J Basin is located in northeastern Colorado, and for more than 15 years
has been the Company's primary producing region. HSR's D-J Basin production and
reserves are largely found in the Codell, Niobrara, D-Sand and J-Sand formations
with additional production from the deeper 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 gas. 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. With
the addition of the Amoco Properties, the Company's producing assets in this
area are comprised primarily of wells producing from the Codell, Niobrara and
J-Sand formations. The Codell and Niobrara formations are found at depths
ranging from 6,400 to 7,700 feet and the J-Sand is found between 7,400 and 7,800
feet. Codell and Niobrara wells produce oil and gas, while J-Sand wells produce
primarily gas. All of the gas from this field has high Btu content, allowing for
extraction of natural gas liquids.
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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, gas
or both. Within the D-Sand and J-Sand, high porosities and permeabilities can
yield higher flow rates than Wattenberg wells. D-Sand and J-Sand channels, while
not "blanket" formations, 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 three geological
areas: (i) the Anadarko Basin in western Oklahoma and the Texas panhandle, (ii)
the Arkoma Basin in southeastern Oklahoma and western Arkansas and (iii)
southern Oklahoma.
Anadarko Basin. The Anadarko Basin is a major Mid-Continent oil and 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 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
formations. Oil and 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. It is a major 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
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.
Gulf Coast
The Company has established a core geographic area in onshore south Louisiana
and the upper Texas Gulf Coast. Its activities focus on both shallow
exploitation and deeper exploration targets in those areas. Focus areas are
Acadia, Jefferson Davis, Beauregard, Calcasieu, St. Landry and Evangaline
Parishes of south Louisiana and Chambers, Ft. Bend and Matagorda Counties in the
upper Texas Gulf Coast. Wells in the area target the Frio, Vicksburg, Cockfield,
Yegua, Sparta, and Hackberry formations at depths ranging from 3,000 to 13,500
feet. The complex faulted and prolific salt dome dominated region possesses
numerous 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.
12
<PAGE> 13
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 of approximately
11,000 feet. Although most of HSR's 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, 1997.
<TABLE>
<S> <C>
Development and exploitation locations . . . . . . . . . 2,200
Potential infill locations . . . . . . . . . . . . . . . 700
Recompletion and refrac locations . . . . . . . . . . . 1,200
Exploration leads and prospects . . . . . . . . . . . . 315
3-D seismic data (square miles) . . . . . . . . . . . . 985
</TABLE>
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, refrac projects, potential increased density
drilling, wellbore extensions, and exploration leads.
Wattenberg Field Area. The Company drilled 41 wells in Wattenberg during 1997,
accounting for additional production of approximately 2,541 Mcf of gas and 365
Bbl of oil production per day as of December 31, 1997. In addition to the over
2,100 opportunities provided by the Amoco Acquisition, HSR has in inventory 900
development drillsites, of which 584 are included in proved undeveloped
reserves. In addition, the Company has identified approximately 240 recompletion
opportunities in Wattenberg and at least 250 potentially economic infill
drillsites.
By combining the Amoco Properties with those previously owned by the Company,
HSR now owns numerous low-risk, potentially high-return development
opportunities. Because the Company owned formations that were vertically stacked
over and under formations previously owned by Amoco, the Company can now utilize
existing HSR or former Amoco wells to obtain potential reserves that were not
available or economic to either Amoco or HSR before the Amoco Acquisition. For
example, an existing HSR Codell well can be deepened a few hundred feet to reach
the J-Sand or Dakota formations previously owned by Amoco, or an existing Amoco
J-Sand well can be recompleted uphole to produce from the Codell, Niobrara,
Sussex or Shannon
13
<PAGE> 14
formations that have been owned by HSR for some time but were not economically
attractive enough to justify the drilling of a new well. Production from the
various formations can generally be commingled.
The Company has also undertaken a program to increase Codell production from
existing wells through a process of restimulating (or "refracing") the currently
producing formation. The Company has completed 53 refracs through year end, all
of which were successful. Through the refrac process, the Company restimulated
each well to achieve production levels, reserve increases and decline profiles
approaching the well's initial characteristics. The Company believes that there
are more than 500 opportunities for this type of well stimulation. In addition,
gas production from many of the refrac candidates generate Section 29 tax
credits of approximately $0.60 per Mcf, which the Company monetizes under its
existing Section 29 monetization arrangements.
Greater D-J Basin. The Greater D-J Basin, in which the Company owns rights to
more than 173,000 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. In 1997,
the Company drilled and completed 21 wells, accounting for additional production
of approximately 1,146 Bbl of oil per day and 4,497 Mcf of gas per day. Thirteen
active projects and leads in this area are under review by the Company's
geotechnical staff.
Mid-Continent Projects
The Company has identified over 213 potential development and exploitation
drilling opportunities and 68 recompletion opportunities in the Mid-Continent.
In 1997, the Company participated in the drilling of 32 wells adding net
production of approximately 2,809 Mcf per day of gas as of December 31, 1997.
The Company also performed 20 recompletions.
In the Anadarko Basin, following the transfer of properties to Amoco in
connection with the Amoco Acquisition, the Company owns interests in 405 wells
in various fields which provide numerous potentially attractive development and
exploitation opportunities. The Company has identified approximately 84 drilling
and 51 recompletion opportunities in various fields. In 1997, the Company
drilled a successful well extending the existing Bivins Ranch field, creating
the opportunity for an additional three to five offset wells.
In the Arkoma Basin, the Company owns interests in 384 wells in the Kinta,
Bokoshe, Russellville, Wilburton and other fields. The Company has identified
approximately 129 drilling and 17 recompletion opportunities.
Other areas present additional opportunities. For example, with the use of 3-D
seismic data, the Company has identified further drilling opportunities at La
Reforma field in northwestern Hidalgo County, Texas, in which the Company owns
interests in a 5,100 acre contiguous block. The Company drilled two successful
wells at La Reforma in 1997 and expects to participate in an additional well in
1998. Further potential in this area is currently being evaluated.
14
<PAGE> 15
Gulf Coast Projects
The Company's onshore Gulf Coast activity is focused in southwest Louisiana and
southeast Texas. The Company has been developing prospects in 18 active project
areas. To date, the Company has acquired over 530 square miles of 3-D seismic
data to support the exploration effort.
During 1997, the Company's Gulf Coast exploration program entered the drilling
phase on several projects. The Company participated in 16 gross wells, 11 of
which were successful. The most significant discovery is the HSR Carter #1 well
in the Roanoke project, which is currently producing 8.2 MMcf and 127 Bbl per
day. Gross year end reserves are estimated to be 2.5 million Boe for this well.
In addition, the Buhler project has now drilled nine successful wells in 11
attempts, with reserves averaging 512,000 Boe per well. Although the Company has
a small interest in the Buhler project, the technology gained from the program
has provided the basis for developing three additional project areas, in which
the Company's working interests range from 25% to 50%. For example, the North
Gillis program in Calcasieu Parish, Louisiana, in which the Company has a 37.5%
working interest, is a direct offset and analog to the successful Buhler
project. This project targets Hackberry and Yegua sands. The 3-D seismic survey
is complete with drilling to commence in the first half of 1998.
The Company has a 25% working interest in the Iowa/Welsh 3-D project operated by
Sonat Exploration, Inc. in Jefferson Davis Parish, Louisiana. The 135 square
mile 3-D seismic survey has been completed and initial drilling is expected to
follow in late 1998.
At the Port Barre project in St. Landry Parish, Louisiana, the Company has
completed the field acquisition phase of a 55 square mile 3-D seismic survey.
Initial drilling is expected to commence in the second half of 1998. The Company
has a 100% working interest in the Port Barre program.
Northern Rocky Mountain Projects
The Company's strategic focus for the Northern Rocky Mountain area is to
optimize production, fund exploratory activity through joint ventures, and
continue evaluation of undeveloped acreage. The Company has entered into
agreements with several operators with specific areas of technological or
operational expertise to evaluate and exploit certain of its large acreage
positions. By year end, this effort resulted in the drilling of four wildcats
with three additional wells currently being drilled, and the acquisition of over
73 square miles of 3-D seismic data.
For example, the Company has entered into an agreement with Union Pacific
Resources Company ("UPRC") on nearly 300,000 gross undeveloped acres in Daniels
County, Montana in the Williston Basin. Through the agreement, UPRC has drilled
two dual-lateral horizontal wells and one single-lateral horizontal well. All
three wells are currently on production and under evaluation.
15
<PAGE> 16
In Richland and Roosevelt County, Montana, HSR has entered into joint venture
agreements with experienced local operators. These agreements resulted in the
drilling of two exploratory wells and the acquisition of 32 square miles of 3-D
seismic data. Both wells were dry holes. The seismic data is awaiting
interpretation.
The Company retains a significant acreage position in the Greater Green River
Basin, one of the most active areas in the Northern Rocky Mountains. New
geophysical, drilling and completion technologies appear to be unlocking
high-potential exploration opportunities targeting over-pressured basin-centered
gas.
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 671,271 developed and 780,821 undeveloped net acres as of December
31, 1997.
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, 1997.
<TABLE>
<CAPTION>
Developed Acres (1) Undeveloped Acres (1)
--------------------- ---------------------
Area Gross Net Gross Net
- ---- ------- --------- --------- --------
<S> <C> <C> <C> <C>
D-J Basin 571,217 536,301 275,136 246,082
Mid-Continent 349,279 130,030 33,862 28,572
Gulf Coast 3,027 497 334,575 160,180
Northern Rocky Mountains 13,941 4,443 593,345 345,987
------- ------- --------- -------
Total 937,464 671,271 1,236,918 780,821
======= ======= ========= =======
</TABLE>
(1) Includes acres upon which the Company owns the rights to conduct seismic,
exploration and development activity but is not the lessee.
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, 1997. Williamson Petroleum Consultants, Inc. reviewed HSR's D-J 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, 1997. 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, 1997, 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
16
<PAGE> 17
owned by the Company. In the aggregate, 84% of the Company's pre-tax present
value for the total proved reserves were reviewed by the two engineering firms.
<TABLE>
<CAPTION>
Net Proved Reserves
as of December 31, 1997
---------------------------------
Developed Undeveloped Total
--------- ----------- --------
<S> <C> <C> <C>
Oil and condensate (MBbl) 26,028 19,330 45,358
Gas (MMcf) 611,198 268,656 879,854
Equivalent barrels (MBoe) 127,894 64,106 192,000
Present value of estimated
future net revenues before income
taxes (discounted at 10%) (in thousands) $699,853 $122,613 $822,466
</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, either upward or downward, 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. 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, 1997, were $16.38 per
Bbl of oil and $2.31 per Mcf of gas. 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" and the Company's report on Form 8-K filed
with the Securities and Exchange Commission on February 26, 1997.
For further information concerning the present value of future net revenue from
the Company's proved reserves, see Note 14 of the Notes to Consolidated
Financial Statements.
17
<PAGE> 18
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,
----------------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
Development:
Productive 65.3 116.7 69.7
Non-productive 5.3 0.0 5.4
------ ------ ------
Total 70.6 116.7 75.1
------ ------ ------
Exploratory:
Productive 14.2 3.5 21.3
Non-productive 9.7 0.0 12.3
------ ------ ------
Total 23.9 3.5 33.6
------ ------ ------
Total wells 94.5 120.2 108.7
====== ====== ======
</TABLE>
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, 1997, 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 2,871 1,558 4,429 2,648.7 140.4 2,789.1
Gas 482 464 946 347.9 85.8 433.7
------- ------- ------- ------- ------- -------
Total 3,353 2,022 5,375 2,996.6 226.2 3,222.8
======= ======= ======= ======= ======= =======
</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.
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<PAGE> 19
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 (dollars in thousands).
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------
1997 1996 1995
-------- -------- ---------
<S> <C> <C> <C>
Acquisition costs:
Unproved properties $131,262 $ 35,227 $ 4,343
Proved properties 167,825 338,814 25,015
Development costs 46,678 37,819 29,989
Exploration costs 12,856 2,100 2,748
-------- -------- --------
Total costs incurred $358,621 $413,960 $ 62,095
======== ======== ========
</TABLE>
PRODUCTION
The following table sets forth the Company's oil and gas production data during
the periods indicated.
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
Net production:
Oil and condensate (MBbl) 2,400 1,923 1,582
Gas (MMcf) 41,125 34,163 21,049
Equivalent barrels (MBoe) 9,254 7,617 5,090
Average net daily production (1):
Oil and condensate (Bbl) 6,679 5,255 4,333
Gas (Mcf) 117,589 93,342 57,670
Equivalent barrels (Boe) 26,277 20,812 13,945
Average sales price per unit:
Oil and condensate ($/Bbl) $ 19.71 $ 20.90 $ 16.52
Gas ($/Mcf) $ 2.19 $ 1.96 $ 1.30
Lease operating expense ($/Boe) $ 2.69 $ 2.32 $ 1.95
</TABLE>
(1) Average daily production for 1997 was calculated for the quarter ended
December 31, as the results are believed to be more indicative of current
performance.
19
<PAGE> 20
Item 3. LEGAL PROCEEDINGS AND ENVIRONMENTAL ISSUES
Litigation. On July 22, 1997, Chenier Exploration, Inc. ("Chenier") brought suit
against the Company in the United States District Court for the Eastern District
of Texas (Chenier Exploration, Inc. v. HS Resources, Inc., Civil Action No.
1:97-CV-399) seeking damages and certain preliminary relief arising out of the
termination of an Exploration and Development Agreement ("Agreement") between
Chenier and the Company. The Agreement called for, among other things,
cooperation between the companies in the identification and development of oil
and gas prospects in the Gulf Coast regions of Louisiana and Texas. On August
22, 1997, the Court denied Chenier's requests for preliminary relief and granted
the Company's request that the remaining disputes between Chenier and the
Company be resolved in an arbitration conducted under the auspices of the
American Arbitration Association ("AAA") and entitled In re HS Resources, Inc.
and Chenier Exploration, Inc., AAA Arbitration No. 77-180-00171-97.
Chenier asserted that the Company breached express and implied provisions of the
Agreement in connection with its termination of that Agreement, that the Company
acted in bad faith in connection with the Agreement and that the Company
wrongfully interfered with employment and other existing and prospective
agreements involving Chenier in connection with the termination of the
Agreement. The Company denied each of these claims and believed it had
substantial legal defenses to each of the claims, and vigorously defended
against them. These claims were addressed in an arbitration hearing which
commenced on February 2, 1998, and ended February 17, 1998. On March 26, 1998,
the arbitrator issued a final award in favor of the Company denying each of
Chenier's claims for damages.
Additionally, 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 results of operations or financial
position.
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
20
<PAGE> 21
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 $1.4 million 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, 1997, financial statements.
Recent data regarding site conditions indicate a potentially more significant
contamination problem in one portion of the site which is the apparent result of
disposal of non-oil field wastes by third parties a number of years prior to the
Company's involvement as an oil field waste disposal customer of this facility.
This recent data gives rise to both the possibility of a defense of
non-liability for the divisible harm caused by wastes of third parties and
greater uncertainty regarding the total costs of study and clean-up for which
the Company is potentially liable. For these reasons, and because even the
selection of a remedial plan has yet to occur, the Company is not able at this
time to determine its probable share, if any, of future response costs for these
non-oil field wastes.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
21
<PAGE> 22
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock (NYSE symbol "HSE") is traded publicly on the NYSE.
The following table presents the high and low sales prices reported by the NYSE
for the periods indicated. These prices do not include retail markups, markdowns
or commissions.
<TABLE>
<CAPTION>
Quarter ended High Low
- -------------------- ------ ---------
<S> <C> <C>
March 31, 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
March 31, 1997 18 3/8 11 1/2
June 30, 1997 15 10 7/8
September 30, 1997 17 7/8 13 3/16
December 31, 1997 18 3/4 12 5/8
</TABLE>
As of December 31, 1997, there were 422 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.
22
<PAGE> 23
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, Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations."
<TABLE>
<CAPTION>
(In thousands, except per share amounts and average prices)
For the Years Ended December 31,
1997 1996 1995 1994 1993
------------ ----------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C>
Statement of Operations Data
Oil and gas sales $ 137,251 $ 107,281 $ 53,394 $ 58,827 $ 45,382
Trading and transportation 90,062 46,373 -- -- --
Other revenues 6,392 3,302 1,946 1,574 2,095
----------- ----------- ----------- ----------- -----------
Total revenues 233,705 156,956 55,340 60,401 47,477
----------- ----------- ----------- ----------- -----------
Production taxes 9,703 8,195 4,050 5,134 4,222
Lease operating expenses 24,848 17,692 9,936 8,310 5,470
Cost of trading and transportation 88,402 45,699 -- -- --
Depreciation, depletion and amortization 53,241 42,335 26,609 25,079 15,299
General and administrative expenses 7,987 5,642 4,076 4,228 3,123
Interest expense 31,204 22,936 10,219 7,539 3,118
----------- ----------- ----------- ----------- -----------
Total expenses 215,385 142,499 54,890 50,290 31,232
----------- ----------- ----------- ----------- -----------
Income before provision for income
taxes 18,320 14,457 450 10,111 16,245
Provision for income taxes (6,980) (5,508) (176) (3,852) (6,189)
----------- ----------- ----------- ----------- -----------
Net income $ 11,340 $ 8,949 $ 274 $ 6,259 $ 10,056
----------- ----------- ----------- ----------- -----------
Diluted earnings per share $ 0.64 $ 0.61 $ 0.02 $ 0.53 $ 0.93
----------- ----------- ----------- ----------- -----------
Weighted average number of common shares
outstanding assuming dilution 17,593 14,552 11,439 11,713 10,858
----------- ----------- ----------- ----------- -----------
Balance Sheet Data
Working capital (deficiency) $ (9,042) $ 13,749 $ (16,115) $ (2,384) $ 16,221
Oil and gas properties, net 959,536 652,180 278,811 242,009 184,188
Total assets 1,034,603 731,285 302,089 269,070 228,260
Long-term debt, net of current portion 636,699 398,563 125,537 103,478 74,420
Deferred income taxes 90,798 84,829 23,604 23,432 19,589
Stockholders' equity 223,622 192,724 119,174 119,358 113,299
Operating Data
Average sales price per barrel of oil $ 19.71 $ 20.90 $ 16.52 $ 14.83 $ 16.09
Average sales price per thousand
cubic feet of gas $ 2.19 $ 1.96 $ 1.30 $ 1.70 $ 2.03
Production
Oil (MBbl) 2,400 1,923 1,582 1,664 967
Gas (MMcf) 41,125 34,163 21,049 20,108 14,684
MBoe 9,254 7,617 5,090 5,015 3,414
Net cash provided by
operating activities $ 94,019 $ 52,251 $ 31,179 $ 36,553 $ 33,745
</TABLE>
23
<PAGE> 24
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL For the last several years the Company pursued a strategy that included
(i) building a substantial inventory of development, exploitation and
exploration projects, (ii) consolidating in its core geographic areas,
particularly the Denver-Julesburg ("D-J") Basin, (iii) diversifying its asset
base into multiple geographic and geologic regions of the United States, (iv)
capturing more of the value stream by marketing its production and (v)
maximizing its financial flexibility. The Company's success over the past 18
months in accomplishing these goals has positioned the Company for a period of
significant growth in reserves, production, and cash flow. Having achieved its
historic goals, the Company has now adopted the four part strategy involving
Consolidation, Exploitation, Exploration and Technology discussed in Item 1.
"BUSINESS STRATEGY."
Through the 1997 acquisition of all of Amoco Production Company's D-J Basin
properties (the "Amoco Acquisition") and the 1996 acquisition of all of the D-J
Basin properties owned by Basin Exploration, Inc. (the "Basin Acquisition"), the
Company has expanded its D-J Basin asset base and significantly increased its
inventory of development, exploitation and exploration opportunities. As a
result of the 1996 merger (the "Merger") with Tide West Oil Company ("Tide
West"), and by establishing an active Gulf Coast exploration program, the
Company also has developed a substantial base of assets outside of the D-J
Basin.
Through the execution of its strategy, the Company now operates in four core
areas. Additionally, the Company's strategically important and profitable
presence in the gas marketing, trading and transportation business through its
subsidiary, HS Energy Services, Inc. ("HSES"), provides opportunities for the
Company to enhance its operating margins on production from each of its
producing areas.
The Amoco Acquisition presents the Company with new opportunities, challenges
and potential directions. That acquisition, in combination with the Company's
recent success in finding new D-J Basin reserve potential through scientific,
technical and operational advances, materially increases the number of low-risk,
high-return projects that the Company owns in the D-J Basin. Therefore, based on
its existing inventory of opportunities, the Company expects that the D-J Basin
will once again become dominant in the Company's strategy for growth. However,
as the Company pursues its D-J Basin growth opportunities it will also continue
to pursue development in its other core areas.
The Amoco Acquisition required the Company to borrow funds, which has increased
its leverage ratios significantly. As a result, although the Company has
executed a number of commodity price and interest rate hedge agreements designed
to moderate this risk, the current level of debt will increase interest expense
and make the Company more vulnerable to changes in interest rates and commodity
prices. The increased activities in the D-J Basin, however, are expected to
reduce the Company's per unit production costs, as discussed below. For various
reasons, as discussed in Item 7. "LIQUIDITY AND CAPITAL RESOURCES--Financing
Sources" below, the Company believes the current level of debt is acceptable,
although it is considering a wide range of future financing alternatives.
OIL AND GAS PRICES 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. Through 1997,
several factors had a positive effect on
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<PAGE> 25
production economics in the Company's core geographic areas as compared to the
period 1994 through 1995. These include (i) relatively high wellhead capacity
utilization, (ii) increasing overall gas demand, (iii) deregulation of
distribution and marketing channels, particularly for D-J Basin and Rocky
Mountain production, and expansion of pipeline capacity to transport gas to
markets outside the Colorado Front Range and (iv) successful application of
advanced oil and gas exploration, drilling and production technologies. However,
uncertainty concerning the price of oil and gas remains a dominant and
unpredictable factor in the Company's profitability.
GAS PRICE CONSIDERATIONS Approximately 81% of the Company's proved producing
reserves consist of gas located in the D-J Basin and Mid-Continent areas. The
absolute level and volatility of gas prices have a material impact on the
Company.
Since the beginning of 1996, the market for the Company's D-J Basin gas has
strengthened substantially due to several factors. First, excess supply from
Wyoming gas producers has declined as a result of increased demand from West
Coast markets. Second, in October 1995 the Colorado Public Utilities Commission
("CPUC") approved tariff changes that effectively eliminated transportation
costs for D-J Basin gas sold to the Colorado Front Range market, resulting in a
transportation cost advantage for D-J Basin producers of approximately $0.40 per
million British thermal units ("MMBtu"). Some of this advantage may be
eliminated if the application filed by Public Service Company of Colorado
("PSCO"), discussed below, is approved in its current form. Third, the supply of
D-J Basin gas has declined over the last two years due to the combination of
reduced drilling in the D-J Basin and natural production declines. The average
price received by the Company for its D-J Basin gas production has increased
from $1.28 per Mcf in 1995 to $1.90 per Mcf in 1996 and to $2.13 per Mcf in
1997. In addition, expansion of pipeline capacity has provided additional
transportation outlets for Wyoming producers to markets other than the Colorado
Front Range and also provided Colorado Front Range producers with access to
other markets.
As a result of these developments, the disparity between D-J Basin pricing and
pricing generally available elsewhere in the United States has been reduced.
Historically, the price of D-J Basin gas (on a Btu-equivalent basis) has been
linked closely to the Colorado Interstate Gas Company ("CIG") pipeline Rocky
Mountain Index. More recently, however, as a result of the developments
discussed above and the seasonal nature of demand in the Colorado Front Range,
during the low demand summer months (generally April through October) the price
for D-J Basin gas tends to reflect the CIG Rocky Mountain Index, whereas during
the high demand winter periods (generally November through March) the price more
closely tracks Mid-Continent indices.
In recent months two proposals have been filed to build pipelines between the
Colorado Front Range market area and Wyoming. A subsidiary of K N Energy has
proposed a 250 MMcfd capacity pipeline which is currently before the Federal
Energy Regulatory Commission. PSCO and CIG, through a jointly owned affiliate,
have proposed a 270 MMcfd capacity line. As proposed, the PSCO line would be
operated as part of PSCO's local distribution system, moving the city gate to
PSCO's Chalk Bluffs measurement station near the Wyoming border. If approved as
proposed, this would eliminate some portion of the advantage the Company
currently has over
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<PAGE> 26
Wyoming producers for direct sales in the Colorado Front Range market. The PSCO
application is currently before the CPUC. Approval of either or both of these
pipelines would increase the amount of Wyoming gas that could be transported to
the Colorado Front Range market, while also expanding the amount of gas that
could be exported from the D-J Basin to Mid-Continent and West Coast markets
through Wyoming pipeline interconnections. The Company has intervened in both
the K N Energy and PSCO application proceedings, and is protesting the PSCO
application. The Company cannot predict whether these pipeline applications will
be approved, amended or denied, nor what would be the ultimate effect on the
price of the Company's D-J Basin gas if either or both are approved.
Gas prices in the Mid-Continent are closely tied to established indices which
are influenced by national supply and demand factors. Average 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 1997 averaged
$0.24 per MMbtu less than the Henry Hub price. The average gas price received in
the Mid-Continent since the Merger in June 1996 through December 31, 1997, was
$2.29 per Mcf, or $0.27 below the Henry Hub price, before considering the
effects of 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 crude oil closing prices. Weaknesses in the world oil demand
coupled with increasing supplies from the Middle East led to weak oil prices
over the recent winter months, reaching a four-year low before recovering
somewhat in the most recent two weeks. The Company is unable to predict the
future trend in oil prices.
RESULTS OF OPERATIONS During 1997 the Company continued drilling and development
activity in the D-J Basin, exploitation and exploration activities in the
Mid-Continent and the Gulf Coast regions and completed the Amoco Acquisition. At
December 31, 1997, the Company owned interests in more than 5,300 producing
wells (of which it operated more than 3,300) compared to 3,500 wells (of which
it operated more than 2,600) at December 31, 1996. The Company's results of
operations have been significantly affected by the Basin Acquisition and the
Merger, by its drilling program and by fluctuations in oil and gas prices.
Future results will also be significantly affected by the Amoco Acquisition and
the Company's exploration, exploitation and development activities.
Per unit lease operating expense ("LOE") and general and administrative ("G&A")
costs are expected to decrease due to efficiencies in combining the assets
acquired in the Amoco Acquisition with the Company's previously existing asset
base. These benefits will be offset to some extent by the increase in interest
expense attributable to the Company's expected debt level. In the Amoco
Acquisition, the Company purchased 2,068 producing wells in the D-J Basin as
well as more than 2,100 low-risk development opportunities. At December 31,
1997, production attributable to the producing wells acquired from Amoco totaled
8,353 Boe per day, increasing the Company's overall production, revenues and
cash flow. In addition, the Company plans to increase its development activities
in the D-J Basin to exploit the large number of development opportunities in
this area.
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<PAGE> 27
The United States oil and gas industry is currently experiencing regional
shortages of drilling and completion equipment and skilled workers. This
shortage has resulted in higher costs for the Company's drilling and related
field activities, primarily in its Gulf Coast and Mid-Continent district
operations. The Company anticipates this shortage will continue for the
foreseeable future.
COMPARISON OF YEARS ENDED DECEMBER 31, 1997 AND 1996
OIL AND GAS REVENUES For the comparative periods, oil production increased from
1,923 MBbl to 2,400 MBbl and gas production increased from 34,163 MMcf to 41,125
MMcf, or 25% and 20%, respectively. Average realized oil prices decreased by 6%
from $20.90 to $19.71 per Bbl and average realized gas prices increased by 12%
from $1.96 to $2.19 per Mcf. The production increases were primarily the result
of additional production from the properties acquired in the Basin Acquisition
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 $107 million to
$137 million, or 28%. In 1997 the Company also recognized $4.4 million in other
gas revenues from the sale of tax credits compared to $2.7 million in 1996, as
discussed in Note 11 of the Notes to Consolidated Financial Statements.
Through its wholly owned subsidiary HSES, the Company markets its own gas
production as well as that of third parties. A portion of this gas is sold
directly to end users, while other amounts are used as the equity-gas foundation
for a physical trading business in which gas volumes may be traded several times
at different receipt and delivery points in order to capture the greatest margin
possible. Trading and transportation net margins were $1.7 million at December
31, 1997, compared to $0.7 million at December 31, 1996.
INTEREST INCOME AND OTHER INCOME Interest and other income increased by $1.4
million, or 234%, for the year ended December 31, 1997. The increase was mainly
due to interest received for prior year severance tax refunds, short term
investing of the Company's available funds, and income recorded on the Company's
interest in a limited partnership.
PRODUCTION EXPENSES LOE increased by $7.2 million, or 40%, due to an increase in
the number of producing wells. On a per Boe basis, LOE increased from $2.32 to
$2.69 for the comparative periods, which is primarily the result of a different
mix of wells in the current year, including wells with historically higher
operating costs which were obtained as a result of the Basin Acquisition, and a
significant number of workovers on producing wells. LOE per Boe is expected to
decrease in 1998 as the efficiencies of consolidation of the Amoco assets are
realized. Production taxes increased by $1.5 million, or 18%, due to increased
production and prices. Production taxes in 1997 reflect an adjustment for prior
year severance tax refunds.
DEPRECIATION, DEPLETION AND AMORTIZATION DD&A, a non-cash expense, increased
$10.9 million, or 26%, due to an increase in production and an increase in the
depletion rate. For the year ended December 31, 1997, the Company had a weighted
average depletion rate of $5.54 per Boe ($5.89 for the quarter ended December
31, 1997) compared to $5.33 per Boe for the year ended December 31, 1996. The
Company annually adjusts its DD&A rate based on year end engineering and, if
material changes in its reserves warrant, on an interim basis.
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<PAGE> 28
GENERAL AND ADMINISTRATIVE EXPENSE G&A expense reflects costs incurred, net of
administrative costs directly attributable to drilling and well operations
(which costs are included in LOE or are capitalized). G&A expenses increased
$2.3 million, or 42%. The increase for the comparative periods is primarily
attributable to the administrative costs resulting from the Merger and the
greater number of Tide West employees, as well as the addition of personnel and
facilities throughout 1997 which were required in order to accomplish the
Company's acquisition, drilling and exploration objectives. On a per Boe basis,
G&A expenses increased from $0.74 to $0.86 for the comparative periods. The
current year per Boe amount is generally in line with prior years, but is
expected to decrease as the D-J Basin assets are developed and produced in 1998.
The period-over-period comparative difference results substantially from the
abnormally low costs incurred by the Company in the prior year, particularly
during the transitionary period immediately after closing the Basin Acquisition
and the Merger. During that transitionary period costs were anomalously low
while the Company hired additional staff to handle the ongoing requirements
attributable to the increase in operations.
INTEREST EXPENSE Interest expense increased $8.3 million, or 36%, due to the
overall increase in long-term debt attributable to the Basin Acquisition and the
Merger as well as amounts borrowed in December 1997 to fund the Amoco
Acquisition. Interest expense is expected to increase significantly in 1998 due
to increased borrowings used to fund the Amoco Acquisition.
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 1997 and
1996. Due to significant intangible drilling costs, which are deductible for
income tax purposes, substantially all of the Company's tax provision in both
periods is deferred.
COMPARISON OF YEARS ENDED DECEMBER 31, 1996 AND 1995
OIL AND GAS REVENUES For the comparative periods, oil production increased from
1,582 MBbl to 1,923 MBbl and gas production increased from 21,049 MMcf to 34,163
MMcf, or 22% and 62%, respectively. Average realized oil prices increased by 27%
from $16.52 to $20.90 per Bbl and average realized gas prices 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 Basin Acquisition 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 11 of the
Notes to Consolidated Financial Statements.
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<PAGE> 29
As discussed above, the Company, through its wholly owned subsidiary HSES,
markets its own gas production as well as that of third parties. Trading and
transportation net margins were $0.7 million 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 LOE increased by $7.8 million, or 78%, due to an increase in
the number of producing wells. LOE per Boe increased from $1.95 to $2.32 for the
comparative periods. This increase is primarily the result of a different mix of
wells, including wells with historically higher operating costs which were
acquired as a result of the Basin Acquisition. Production taxes increased by
$4.1 million, 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 DD&A, a non-cash expense, increased
$15.7 million, 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
average depletion rate of $5.33 per Boe ($5.41 for the quarter ended December
31, 1996). The Company annually adjusts its DD&A rate based on year end
engineering, and, if material changes in its reserves warrant, on an interim
basis.
GENERAL AND ADMINISTRATIVE EXPENSE G&A expense reflects costs incurred, net of
administrative costs directly attributable to drilling and well operations
(which costs are included in LOE or are capitalized). G&A expenses increased
$1.6 million, or 38%. The increase for the comparative periods is primarily
attributable to the Merger and retention of the former Tide West employees. On a
per Boe basis, G&A expenses decreased from $0.80 to $0.74 for the comparative
periods.
INTEREST EXPENSE Interest expense increased $12.7 million, 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 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 income tax purposes, substantially all of the Company's
tax provision in both periods is deferred.
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<PAGE> 30
LIQUIDITY AND CAPITAL RESOURCES
Financing Sources
At December 31, 1997, the Company's overall debt level was significantly higher
than in previous periods as a result of borrowings used to fund the Amoco
Acquisition. The Company believes that its current level of debt and leverage is
acceptable at present, although the Company may elect to reduce or refinance
such debt levels at any time. The Company's debt is supported by stable,
long-lived reserves and by the Company's hedging programs, with product prices
hedged for reasonable periods of time at favorable prices. Cash flow from
producing activities is sufficient to enable the Company to service its debt,
absent any major and prolonged period of price declines. The Company has a large
number of low-risk, potentially high-return exploitation projects which should
enhance production and cash flow per share. In light of this view, and as part
of an overall financing strategy, the Company is considering a wide range of
future financing alternatives and is not committed to any particular course.
In undertaking any future financing transactions, the Company will seek to
achieve the optimal capital structure needed to support its long-term strategic
objectives. Any such financings will reflect market conditions at the time and
may include the issuance of long-term debt, equity, or equity-linked securities.
In addition to or perhaps in lieu of the issuance of such securities, to
optimize its capital structure the Company may sell or monetize certain
properties, which would also minimize the equity dilution which would otherwise
result from the issuance of additional equity securities. Depending on the
nature and size of such property sales, the Company's production could become
more concentrated in one or more of its existing producing regions.
Because of its increased leverage, the Company currently plans to fund capital
expenditures attributable to exploration, exploitation and development
activities primarily out of its expected cash flow from operations. Accordingly,
the level and volatility of oil and gas prices may be expected to affect the
Company's capital expenditure activities.
On December 15, 1997, as a result of the Amoco Acquisition, the Company's
revolving senior bank credit facility with The Chase Manhattan Bank, as Agent
(the "Chase Facility"), was amended to increase the maximum credit amount and
the borrowing base to $450 million and to revise the interest rate payable
thereunder to the Base Rate plus 0% to 0.625% or LIBOR plus 0.75% to 1.625%.
Under the terms of the Chase Facility, no principal payments are required until
December 15, 2002, assuming the Company maintains a borrowing base sufficient to
support the outstanding loan balance. As of December 31, 1997, $412 million was
outstanding under the Chase Facility. The facility consists of a borrowing base
(currently $450 million) and a threshold amount (currently $400 million --
representing what a fully conforming loan borrowing base would be). The
borrowing base is based on the underlying value of the Company's oil and gas
properties. The borrowing base will remain $450 million until September 15,
1998, at which point it may be redetermined. Until that time, if the Company
issues equity or debt securities, or sells or otherwise disposes of properties,
net proceeds of such transactions must be applied to the repayment of debt under
the facility. The outstanding amounts under the facility must be reduced to or
below the threshold amount by September 15, 1998.
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<PAGE> 31
In November 1996, in a private offering exempt from securities registration, the
Company issued $150 million of its 9 1/4% senior subordinated notes due in 2006
(the "Notes"). The offering of the Notes was undertaken in order to replace with
fixed rate term debt a portion of the Company's outstanding indebtedness under
the Chase Facility. On April 25, 1997, the Company exchanged $150 million of new
notes registered under the Securities Act of 1933 (the "New Notes") for the
Notes. The material terms of the New Notes are identical to those of the Notes.
The Company also maintains its arrangement with a Trust Company of the
West-related entity covering a $90 million non-recourse, volumetric overriding
royalty facility (the "TCW Facility") of which approximately $80 million is
available. 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.
The Company anticipates that its available borrowing capacity under the Chase
Facility, combined with its operating cash flow and the TCW Facility, will
provide it with financial resources and flexibility to fund current and ongoing
development activities and to meet other financial obligations. 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, equity-linked or debt securities, the sale or monetization of properties
or by entering into joint venture arrangements.
Capital Commitments
The Company continuously evaluates its inventory of drilling opportunities to
develop a growth-oriented portfolio of risk-balanced development, exploitation
and exploration opportunities. On an ongoing basis, the Company 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. For the twelve months
ended December 31, 1997, the Company incurred total exploration, development and
leasehold capital expenditures of $75.1 million. The Company estimates that
capital expenditures for 1998 will be approximately $90-$100 million, which will
be allocated in varying amounts primarily to activities in the Company's four
core geographic areas: the D-J Basin, the Northern Rocky Mountains, the Anadarko
and Arkoma Basins of the Mid-Continent and the onshore Gulf Coast region.
A major component of the Company's capital expenditure program relates to its
development activities in the D-J Basin. The Company incurred approximately
$29.2 million in capital expenditures in 1997 for drilling, recompleting and
refracing the Company's D-J Basin properties, and anticipates allocating $60-$75
million in the D-J Basin in 1998.
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<PAGE> 32
A 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. The Company incurred total exploitation and development expenditures
in the Mid-Continent area of $10.8 million during 1997. The Company is currently
evaluating a variety of opportunities in the Mid-Continent that include
increased exploitation, exploration and density drilling, recompletions and
field extensions. The Company anticipates allocating $10-$15 million to these
Mid-Continent projects in 1998.
Another component of the Company's capital expenditure program is to develop
exploitation and exploration prospects in the onshore portion of the Gulf Coast.
In 1997 the Company incurred total capital expenditures of $26.6 million in the
Gulf Coast. This includes approximately $15.3 million of expenditures under its
SouthTech joint venture and $11.3 million on its other Gulf Coast projects, for
seismic, leasehold, overhead costs and drilling. The Company anticipates
allocating $15-$20 million to Gulf Coast projects in 1998.
Activities during 1997 in the Company's Northern Rockies area were designed to
utilize the Company's extensive acreage position as a vehicle for generating
capital expenditures by third party operators on HSR's acreage. During 1997
approximately $10 million was spent or committed to by others to test plays and
concepts on HSR's acreage, with HSR retaining significant positions for
exploiting successful discoveries.
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
Net cash provided by operating activities for the year ended December 31, 1997,
was $94 million, up from $52.3 million for the same period in 1996. This
increase is primarily the result of (i) additional oil and gas production
revenues attributable to the larger number of producing wells resulting from the
Company's drilling activities and the wells acquired in the Basin Acquisition
and the Merger, and (ii) higher gas prices, which were partially offset by lower
oil 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 gas. The Company's
general strategy is to hedge price and location risk with swap, collar, floor
and ceiling arrangements. In order to minimize risk, to the maximum extent
possible, the Company hedges its production back to the wellhead. 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 daily
reporting to management of the potential financial exposure resulting from both
hedging and trading activities.
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<PAGE> 33
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 gas
production and, in the case of its marketing activities, third party gas. Gains
and losses on hedging positions are recognized in the period during which the
underlying physical transactions occur and are booked in "oil and gas sales"
(for company-owned production) and "trading and transportation revenues" (for
third party gas).
The Company's general strategy is to hedge price and location risk with swap,
collar, floor and ceiling arrangements. As a part of its risk management
program, the Company generally enters into hedges for delivery into one of the
two pipelines located near its producing regions, Panhandle Eastern Pipeline
Company ("PEPL") or CIG, or at the New York Mercantile Exchange ("NYMEX") prices
settled at the Henry Hub. With respect to the NYMEX-hedged volumes that exceed
the Company's Gulf Coast volumes, the Company usually hedges basis to its
producing regions at such time as the Company deems advantageous. Currently, the
Company holds hedge swap positions as follows:
<TABLE>
<CAPTION>
Average Daily
Volume Settlement Price
Time Period (MMBtu) Location (per MMBtu)
----------- -------------- ---------- -----------
<S> <C> <C> <C>
January-March 1998 10,000 CIG $2.21
50,000 PEPL $2.53
25,000 NYMEX $2.54
April-October 1998 25,000 CIG $1.66
20,000 PEPL $2.03
16,000 NYMEX $2.22
</TABLE>
The Company has hedged approximately 24% of its expected 1998 oil production at
$19.52 per Bbl. Additionally, with respect to the hedging of third party gas,
the Company has hedged 12.5 Bcf through December 1998 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 a 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
in
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<PAGE> 34
"trading and transportation revenues" as a net gain or loss in the period of
change. The market prices used to value these transactions reflect management's
best estimate considering various factors, including closing exchange and over-
the-counter quotations, time value and volatility factors underlying the
commitments. The values are adjusted to reflect the potential impact of
liquidating the Company's position in an orderly manner over a reasonable period
of time under present market conditions.
Company policy requires that, within defined trading limits, financial
instrument purchase and sales contracts be balanced in terms of contract volumes
and the timing of performance and delivery obligations. As of December 31, 1997,
all material open positions were balanced with an offsetting position. During
1997, gains of $453,821 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 to 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 rates 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 condition or results of
operations.
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<PAGE> 35
See Item 3. "Legal Proceedings and Environmental Issues" and Note 10 of the
Notes to Consolidated Financial Statements.
Year 2000
The Company has completed a review of its systems and infrastructure to
determine the extent of the work needed to ensure Year 2000 compliance. A plan
is being developed to test and verify Year 2000 compliance, including making the
necessary modifications, for all systems and processes. The Company will
continue to evaluate the estimated costs associated with these efforts based on
the results of this work. While these efforts involve additional costs, based on
available information, the Company believes that these costs will not be
material to its results of operations.
35
<PAGE> 36
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," "Management's Discussion and Analysis of Financial
Condition and Results of Operations," and the "Notes to Consolidated Financial
Statements" regarding reserves and their values, planned capital expenditures,
increases in oil and gas production, trends or expectations concerning oil and
gas prices, the number and prospective nature of anticipated wells to be drilled
in 1998 and thereafter, development, infill and drillsite potential,
exploitation and exploration prospects and leads, drilling prospects, drilling
risks, refrac opportunities and expected results, consolidation opportunities,
marketing and trading opportunities and risks, and the Company's financial
position, stability of cash flow, debt service capabilities, capital
availability, debt repayment plans, divestiture plans, business strategy and
other plans and objectives for future operations, potential liabilities or the
expected absence thereof, the potential materiality of year 2000 compliance
expenses and 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 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 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
affect 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. Subsequent to year end, oil prices have declined. If oil
prices are further reduced or if gas prices also decline, now or in the future,
the Company could be required to write down its oil and gas properties,
resulting in a non-cash charge against earnings.
36
<PAGE> 37
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 or in such other sections of this 10-K
Report.
37
<PAGE> 38
CERTAIN DEFINITIONS
The terms defined in this section are used throughout this report.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of gas.
Behind-pipe reserves. Proved reserves in a formation through which production
casing has already been set in the wellbore, but from which production has not
commenced.
Boe. Barrels of oil equivalent, determined using the ratio of six Mcf of gas
(including natural gas liquids) to one Bbl of crude oil or condensate.
Btu. British thermal unit or units. One Btu is the heat required to raise the
temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
COPAS 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 gas in
sufficient quantities to justify completion as an oil or gas well.
Estimated future net revenues. Revenues from production of oil and gas, net of
all production-related taxes, lease operating expenses and capital costs.
Exploitation well or exploitation drilling. Drilling of wells in areas of known
production. However, because of geologic, reservoir and other characteristics it
is possible that an exploitation well may not encounter commercial quantities of
reserves. Therefore such wells carry somewhat greater risk than development
drilling. Oil and gas reserves associated with exploitation wells are not
typically considered to be proved.
Exploratory well or exploratory drilling. A well drilled to find and produce oil
or gas in an unproved area, to find a new reservoir in a field previously found
to be productive of oil or gas in another reservoir, or to extend a known
reservoir beyond existing defined limits.
38
<PAGE> 39
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
gas reserves.
Gross acre. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Held by production. Acreage covered by an oil and gas lease which has a
producing well on it, or which is pooled with a lease or leases having one or
more producing wells on them, so the lease is maintained in effect for the
duration of such production.
Henry Hub. The delivery point of the NYMEX gas contract, located in southern
Louisiana.
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.
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 gas.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
MMBoe. One million barrels of oil equivalent.
39
<PAGE> 40
MMBtu. One million Btus.
MMcf. One million cubic feet of gas.
Multi-pay horizons. A well bore with more than one zone that may potentially
produce oil and/or 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
gas.
Proved developed reserves. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, gas and natural gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
Proved undeveloped location. A site on which a development well can be drilled
consistent with local spacing rules for the purpose of recovering proved
reserves.
Proved undeveloped reserves. Reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required 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 gas
property entitling the owner to a share of oil and gas production free of costs
of drilling, completion and production.
Tcf. One trillion cubic feet of gas.
40
<PAGE> 41
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 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.
41
<PAGE> 42
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONSOLIDATED BALANCE SHEETS
HS Resources, Inc.
<TABLE>
<CAPTION>
December 31,
1997 1996
--------------- ---------------
<S> <C> <C>
Assets
Current Assets
Cash and cash equivalents $ 6,907,708 $ 8,764,756
Margin deposits 3,996 575,712
Accounts receivable
Oil and gas sales 23,052,931 22,601,396
Trading and transportation 14,366,469 17,786,206
Trade 3,579,327 2,255,359
Other 4,711,805 5,625,980
Lease and well equipment inventory, at cost 1,424,301 1,724,944
Prepaid expenses and other 628,797 513,471
--------------- ---------------
Total current assets 54,675,334 59,847,824
--------------- ---------------
Oil and Gas Properties, at cost, using the full cost method
Undeveloped acreage 189,064,119 54,709,553
Costs subject to depreciation, depletion and amortization 951,678,001 727,411,293
Less accumulated depreciation, depletion and amortization (181,205,919) (129,940,868)
--------------- ---------------
Net oil and gas properties 959,536,201 652,179,978
--------------- ---------------
Gas Gathering and Transportation Facilities,
at cost, net of accumulated depreciation of $1,322,382 and
$1,032,224 at December 31, 1997 and 1996, respectively 4,540,806 4,674,075
--------------- ---------------
Other Assets
Deferred charges and other, net 10,254,796 8,954,781
Office and transportation equipment and other property,
net of accumulated depreciation of $5,083,746 and
$3,401,739 at December 31, 1997 and 1996, respectively 4,735,106 4,708,436
Investment in oil and gas limited partnership 860,288 920,285
--------------- ---------------
Total other assets 15,850,190 14,583,502
--------------- ---------------
Total Assets $ 1,034,602,531 $ 731,285,379
=============== ===============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
42
<PAGE> 43
CONSOLIDATED BALANCE SHEETS
HS Resources, Inc.
<TABLE>
<CAPTION>
December 31,
1997 1996
--------------- ---------------
<S> <C> <C>
Liabilities and Stockholders' Equity
Current Liabilities
Accounts payable
Trade $ 18,888,306 $ 9,124,831
Revenue 17,460,848 8,134,201
Gas purchases 7,854,715 13,878,187
Accrued expenses
Ad valorem and production taxes 8,432,221 7,516,095
Interest 3,691,983 3,179,627
Other 7,359,030 4,235,410
Current portion of long-term debt 30,000 30,000
--------------- ---------------
Total current liabilities 63,717,103 46,098,351
--------------- ---------------
Accrued Ad Valorem Taxes 10,606,402 9,005,922
--------------- ---------------
Deferred Revenue (Note 11) 9,872,870 --
--------------- ---------------
Long-Term Oil and Gas Production Note Payable 734,696 734,696
--------------- ---------------
Long-Term Bank Debt, Net of Current Portion 412,000,000 174,000,000
--------------- ---------------
9 7/8% Senior Subordinated Notes,
due 2003, net of unamortized discount of
$346,125 and $404,625 at December 31, 1997
and 1996, respectively 74,653,875 74,595,375
--------------- ---------------
9 1/4% Senior Subordinated Notes,
due 2006, net of unamortized discount of
$689,587 and $767,287 at December 31, 1997
and 1996, respectively 149,310,413 149,232,713
--------------- ---------------
Deferred Income Taxes 90,798,036 84,828,612
--------------- ---------------
Commitments and Contingencies (Note 10)
--------------- ---------------
Minority Interest in Oil and Gas Limited Partnership (713,200) 66,149
--------------- ---------------
Stockholders' Equity
Preferred stock (Note 7) -- --
Common stock, $.001 par value, 30,000,000 shares
authorized; 18,654,545 and 17,127,861 shares issued
and outstanding at December 31, 1997 and 1996,
respectively 18,655 17,128
Additional paid-in capital 183,191,380 163,114,868
Retained earnings 42,773,142 31,433,399
Deferred compensation (144,300) (171,300)
Treasury stock, at cost, 160,358 and 121,952 shares at
December 31, 1997 and 1996, respectively (2,216,541) (1,670,534)
--------------- ---------------
Total stockholders' equity 223,622,336 192,723,561
--------------- ---------------
Total Liabilities and Stockholders' Equity $ 1,034,602,531 $ 731,285,379
=============== ===============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
43
<PAGE> 44
CONSOLIDATED STATEMENTS OF OPERATIONS
HS Resources, Inc.
<TABLE>
<CAPTION>
For the Years Ended December 31,
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Revenues
Oil and gas sales $137,251,046 $107,280,873 $ 53,394,029
Trading and transportation 90,061,787 46,372,707 --
Other gas revenues 4,449,159 2,720,423 1,782,349
Interest income and other 1,942,894 582,067 163,510
------------ ------------ ------------
Total revenues 233,704,886 156,956,070 55,339,888
------------ ------------ ------------
Expenses
Production taxes 9,703,108 8,195,389 4,050,483
Lease operating 24,847,903 17,691,502 9,935,809
Cost of trading and transportation 88,402,012 45,699,154 --
Depreciation, depletion and amortization 53,240,787 42,334,882 26,608,885
General and administrative 7,986,999 5,642,393 4,075,581
Interest 31,204,621 22,935,840 10,218,555
------------ ------------ ------------
Total expenses 215,385,430 142,499,160 54,889,313
------------ ------------ ------------
Income before Provision for Income Taxes 18,319,456 14,456,910 450,575
Provision for Income Taxes 6,979,713 5,508,083 176,419
------------ ------------ ------------
Net Income $ 11,339,743 $ 8,948,827 $ 274,156
============ ============ ============
Basic earnings per share $ 0.66 $ 0.63 $ 0.03
============ ============ ============
Diluted earnings per share $ 0.64 $ 0.61 $ 0.02
============ ============ ============
Weighted average number of common shares
outstanding 17,119,000 14,119,000 10,893,000
============ ============ ============
Weighted average number of common shares
outstanding assuming dilution 17,593,000 14,552,000 11,439,000
============ ============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
44
<PAGE> 45
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
HS Resources, Inc.
<TABLE>
<CAPTION>
For the Years Ended December 31, 1997, 1996, and 1995
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, 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
Merger 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)
---------- --------- ------------ ------------- ---------- -------- -----------
Purchase of treasury stock -- -- -- -- -- (101,247) (1,398,669)
Transfer of treasury
stock to 40l(k)
Plan -- -- (68,011) -- -- 35,894 485,287
Issuance of common stock
for Amoco Acquisition 1,200,000 1,200 19,998,800 -- -- -- --
Exercise of options by
issuance of treasury
stock, including
income tax benefit -- -- (34,355) -- -- 26,947 367,375
Issuance of restricted stock 2,500 3 44,997 -- (45,000) -- --
Amortization of deferred
compensation -- -- -- -- 72,000 -- --
Issuance of common stock 12,203 12 135,393 -- -- -- --
Exercise of warrants and
options 311,981 312 (312) -- -- -- --
Net income -- -- -- 11,339,743 -- -- --
---------- --------- ------------ ------------- ---------- -------- -----------
Balance, December 31, 1997 18,654,545 $ 18,655 $183,191,380 $ 42,773,142 $ (144,300) (160,358) $(2,216,541)
========== ========= ============ ============= ========== ======== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
45
<PAGE> 46
CONSOLIDATED STATEMENTS OF CASH FLOWS
HS Resources, Inc.
<TABLE>
<CAPTION>
For the Years Ended December 31,
1997 1996 1995
------------- ------------- -------------
<S> <C> <C> <C>
Cash Flows from Operating Activities
Net income $ 11,339,743 $ 8,948,827 $ 274,156
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization 53,240,787 42,334,882 26,608,885
Amortization of deferred charges and debenture issue costs 1,830,552 1,082,988 615,368
Transfer of treasury stock to 401(k) Plan 417,276 192,747 378,141
Gain on sale of fixed assets -- (118,649) (52,545)
Deferred income tax provision 5,969,424 5,135,328 171,482
Decrease (increase) in accounts and notes receivable 2,558,409 (21,784,122) 1,113,301
Increase in accounts payable and accrued expenses 7,947,122 16,157,951 2,596,066
Increase (decrease) in deferred revenue, net 9,872,870 -- (1,206,154)
Other 842,595 301,197 680,242
------------- ------------- -------------
Net cash provided by operating activities 94,018,778 52,251,149 31,178,942
------------- ------------- -------------
Cash Flows from Investing Activities
Exploration, development and leasehold costs (75,137,151) (50,626,521) (62,094,658)
Purchase of unproved and proved properties (299,086,755) (129,982,687) --
Cash payment for the Tide West Merger, net of cash acquired -- (85,125,084) --
Gas gathering and transportation facilities additions (156,889) (53,597) (649,469)
Other property additions (1,712,246) (1,056,547) (141,881)
Proceeds from the sale of oil and gas properties 35,602,632 9,678,851 --
Proceeds from the sale of fixed assets and other property -- 157,043 419,116
Increase (decrease) in property related payables 11,272,110 8,130 (2,817,069)
------------- ------------- -------------
Net cash used in investing activities (329,218,299) (257,000,412) (65,283,961)
------------- ------------- -------------
Cash Flows from Financing Activities
Proceeds from debt 337,000,000 536,316,596 48,400,000
Repayments of debt (99,000,000) (315,258,900) (14,000,000)
Tide West Merger costs -- (2,623,792) --
Debt issuance costs (2,947,934) (4,328,056) --
Issuance of common stock 135,405 -- --
Exercise of options 333,020 631,157 10,842
Purchase of treasury stock (1,398,669) (1,460,490) (846,625)
Minority interest, net (779,349) 120,923 --
------------- ------------- -------------
Net cash provided by financing activities 233,342,473 213,397,438 33,564,217
------------- ------------- -------------
Net (Decrease) Increase In Cash and Cash Equivalents (1,857,048) 8,648,175 (540,802)
Cash and cash equivalents, beginning of year 8,764,756 116,581 657,383
------------- ------------- -------------
Cash and cash equivalents, end of year $ 6,907,708 $ 8,764,756 $ 116,581
============= ============= =============
Supplemental Cash Flow Disclosure
Interest paid, net of capitalized interest $ 28,730,596 $ 20,078,634 $ 9,072,167
Cash paid for income taxes, net of reimbursements $ (413,297) $ 418,296 $ --
Schedule of noncash investing and financing activities:
Exchange of properties in Amoco Acquisition $ 23,000,000 $ -- $ --
Common stock issued in Amoco Acquisition $ 20,000,000 $ -- $ --
============= ============= =============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
46
<PAGE> 47
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 Denver-Julesburg ("D-J") Basin, the Anadarko and Arkoma Basins of
the Mid-Continent, the onshore area of the Texas-Louisiana Gulf Coast and the
Northern Rocky Mountains. The Company, through its wholly owned subsidiary HS
Energy Services, Inc. ("HSES"), markets its own gas production, markets gas
owned by third parties and actively trades both physical and financial positions
in the gas commodities market.
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. Capitalized payroll and
other internal costs 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, 1997 and 1996, the
Company excluded costs aggregating $189.1 million and $54.7 million,
respectively, from capitalized costs being amortized. Of the costs excluded at
December 31, 1997, $147.5 million were incurred in 1997, $27.3 million in 1996,
$3.2 million in 1995, $11 million in 1994, and $0.1 million in 1990. The Company
capitalizes interest related to its undeveloped properties. During 1997, 1996,
and 1995, the Company capitalized $4.9 million, $3.3 million, and $2.0 million
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
47
<PAGE> 48
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 gas production and, in the case
of its marketing activities, third party gas. Gains and losses on hedging
positions are deferred and recognized in the period the underlying physical
transactions occur in "oil and gas sales" (for company-owned production) and
"trading and transportation revenues" (for third party gas). Activities for
trading purposes 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 In February 1997 the Financial Accounting Standards Board
issued SFAS No. 128, "Earnings Per Share." This new statement provides
computation, presentation and disclosure requirements for earnings per share
("EPS"). The new standard was effective for the Company for fiscal 1997 and all
prior periods have been retroactively adjusted. Basic EPS is computed based on
the monthly weighted average number of common shares outstanding during the
periods. The weighted average number of common shares used in computing basic
EPS was 17,119,000, 14,119,000 and 10,893,000 for 1997, 1996 and 1995,
respectively. Diluted EPS is computed based on the monthly weighted average
number of common shares outstanding during the periods and the assumed exercise
of dilutive common stock equivalents (stock options and warrants) using the
treasury stock method. Dilutive common stock equivalents assumed to have been
exercised totaled 474,000, 433,000 and 546,000 for 1997, 1996 and 1995,
respectively.
48
<PAGE> 49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
ACCRUED AD VALOREM TAXES The Company classifies as current ad valorem taxes
payable within one year. 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.
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, 1997,
the Company's gas balancing position was approximately 733,000 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.
NEW ACCOUNTING STANDARDS In June 1997, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards No. 130 ("SFAS 130"),
Reporting Comprehensive Income, and SFAS No. 131 ("SFAS 131"), Disclosure about
Segments of an Enterprise and Related Information, which are required to be
adopted for fiscal years beginning after December 15, 1997. SFAS 130 establishes
standards for the reporting and display of comprehensive income and its
components in a full set of general-purpose financial statements. This statement
requires that all items which are recognized under accounting standards as
components of comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements.
Reclassification of financial statements for earlier periods provided for
comparative purposes is required. SFAS 131 requires a public company to report
selected information about its reportable operating segments. Operating segments
are components of an enterprise for which discrete financial information is
available. The Company expects to adopt SFAS 130 and SFAS 131 for the year ended
December 31, 1998.
49
<PAGE> 50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
NOTE 3 - ACQUISITIONS AND MERGER
Effective December 1, 1997, the Company acquired all of the producing and
non-producing properties in the Wattenberg field area of the D-J Basin from
Amoco Production Company ("Amoco") (the "Amoco Acquisition") for $290 million in
cash, 1,200,000 shares of common stock valued at $20 million and the transfer to
Amoco of certain producing Mid-Continent properties valued at $23 million. The
Amoco properties contain estimated proved reserves of 70.2 MMBoe at December 31,
1997 and include interests in 2,068 wells, of which 804 were operated by Amoco.
The Amoco Acquisition was accounted for using the purchase method of accounting
and the Company began consolidating the results of operations on the closing
date of December 15, 1997.
In March and June 1996, the Company acquired all of the D-J Basin oil and gas
properties of Basin Exploration, Inc. ("Basin") (the "Basin Acquisition") for
aggregate cash consideration of $125.5 million. The Basin Acquisition 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. The
Basin Acquisition was accounted for using the purchase method of accounting and
the Company began consolidating the results of operations as of March and June,
1996.
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 daily production
net 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, Texas and Arkansas, 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 (UNAUDITED)
The following table sets forth the condensed unaudited pro forma operating
results of the Company for the twelve months ended December 31, 1997, 1996 and
1995. The condensed pro forma operating results assume that the Amoco
Acquisition had occurred on January 1, 1996, and that both the Basin Acquisition
and the Merger had occurred on January 1, 1995 (see Note 3). The condensed pro
forma results are not necessarily indicative of the results of operations had
the Amoco Acquisition been consummated on January 1, 1996, and the Basin
Acquisition and the Merger been consummated on January 1, 1995, and may not
necessarily be indicative of future performance.
50
<PAGE> 51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
<TABLE>
<CAPTION>
Twelve Months Ended December 31,
(Unaudited)
--------------------------------------------------
1997 1996 1995
------------- ------------- -------------
<S> <C> <C> <C>
Revenues $ 271,213,301 $ 269,413,538 $ 203,407,171
Net income (loss) $ 5,820,980 $ 7,445,679 $ (2,446,727)
Diluted earnings per share $ 0.31 $ 0.40 $ (0.14)
Weighted average number of common shares outstanding assuming dilution 18,740,000 18,608,000 17,600,000
</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 gas. The Company's
general strategy is to hedge price and location risk with swap, collar, floor
and ceiling arrangements. In order to minimize risk, to the maximum extent
possible, the Company hedges its production back to the wellhead. 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 daily
reporting to management of the potential financial exposure 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 gas production and, in the case of its marketing activities, third
party gas. Gains and losses on hedging positions are recognized in the period
during which the underlying transactions occur and are booked in "oil and gas
sales" (for company owned production) and "trading and transportation revenues"
(for third party gas).
The Company's general strategy is to hedge price and location risk with swap,
collar, floor and ceiling arrangements. As a part of its risk management
program, the Company generally enters into hedges for delivery into one of the
two pipelines located near its producing regions, Panhandle Eastern Pipeline
Company ("PEPL") or Colorado Interstate Gas Company ("CIG"), or at the New York
Mercantile Exchange ("NYMEX") prices settled at the Henry Hub. With respect to
the NYMEX hedged volumes that exceed the Company's Gulf Coast volumes, the
Company usually hedges basis to its producing regions at such time as the
Company deems advantageous. Currently, the Company holds hedge swap positions as
follows:
51
<PAGE> 52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
<TABLE>
<CAPTION>
Average Daily
Volume Settlement Price
Time Period (MMBtu) Location (per MMBtu)
------------------ ------------- ---------- -----------
<S> <C> <C> <C>
January-March 1998 10,000 CIG $2.21
50,000 PEPL $2.53
25,000 NYMEX $2.54
April-October 1998 25,000 CIG $1.66
20,000 PEPL $2.03
16,000 NYMEX $2.22
</TABLE>
The Company has hedged approximately 24% of its expected 1998 oil production at
$19.52 per Bbl. Additionally, with respect to the hedging of third party gas,
the Company has hedged 12.5 Bcf through December 1998 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, within defined trading limits, financial instrument purchase and sales
contracts be balanced in terms of contract volumes and the timing of performance
and delivery obligations. As of December 31, 1997, all material open positions
were balanced with an offsetting position.
The Company accounts for these activities using the mark-to-market method of
accounting. During 1997, gains of $453,821 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 to
financial instruments related to hedging activities or trading activities.
52
<PAGE> 53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
NOTE 6 - LONG-TERM DEBT
Debt at December 31, 1997 and 1996 consists of the following:
<TABLE>
<CAPTION>
1997 1996
------------- -------------
<S> <C> <C>
Long-term bank and other debt
Bank debt $ 412,000,000 $ 174,000,000
Other debt 764,696 764,696
------------- -------------
412,764,696 174,764,696
Less-current portion (30,000) (30,000)
------------- -------------
Long-term bank debt and other debt,
net of current portion $ 412,734,696 $ 174,734,696
============= =============
9 7/8% Senior Subordinated notes,
due 2003, net of unamortized discount of
$346,125 and $404,625 at December 31, 1997
and 1996, respectively $ 74,653,875 $ 74,595,375
============= =============
9 1/4% Senior Subordinated notes,
due 2006, net of unamortized discount of
$689,587 and $767,287 at December 31, 1997
and 1996, respectively $ 149,310,413 $ 149,232,713
============= =============
</TABLE>
BANK DEBT On June 7, 1996, the Company entered into a $180 million revolving
senior term credit facility with The Chase Manhattan Bank, as Agent (the "Chase
Facility"), which was amended to $350 million on June 14, 1996. On December 15,
1997, as a result of the Amoco Acquisition, the Chase Facility was further
amended to increase the maximum credit amount and borrowing base to $450 million
and revise the interest rates payable thereunder to the Base Rate plus 0% to
0.625% or LIBOR plus 0.75% to 1.625%. Under the terms of the Chase Facility, no
principal payments are required until December 15, 2002, assuming 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.
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.
53
<PAGE> 54
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 with fixed rate term debt
a portion of the outstanding indebtedness under the Company's bank credit
facility.
CARRYING VALUE At December 31, 1997 and 1996, the carrying amount of the
Company's 9 7/8% senior subordinated notes was $74.7 million and $74.6 million
and the estimated fair value was $77.3 million and $78.3 million, respectively.
At December 31, 1997 and 1996, the carrying amount of the 9 1/4% senior
subordinated notes was $149.3 million and $149.2 million and the estimated fair
value was $153.4 million and $149.2 million, respectively. 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,
1997, are estimated to be their carrying value of $412 million and $0.8 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").
54
<PAGE> 55
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 Company 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 the Company's voting stock. No
separate rights certificates will be issued until at least one of these
thresholds is met. The Rights will expire on March 14, 2006.
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 Company 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 6,000 warrants outstanding and exercisable at $6.67 per
share as of December 31, 1997 and 746,262 warrants outstanding and exercisable
at $8.98 per share as of December 31, 1996 and 1995.
RESTRICTED STOCK In connection with the issuance of 12,500 shares of restricted
stock in 1996 and 1997, the Company recorded $216,300 of deferred compensation
representing 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. Subsequent to
December 31, 1997, the Company issued 23,645 shares of restricted stock. The
Company will record $332,449 of deferred compensation in 1998 and will amortize
such amount over the four year vesting period of the stock.
55
<PAGE> 56
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
NOTE 8 - PROVISION FOR INCOME TAXES
The provision for income taxes consists of the following:
<TABLE>
<CAPTION>
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Current:
Federal $ 200,000 $ 250,000 $ --
State 700,000 50,000 --
---------- ---------- ----------
900,000 300,000 --
---------- ---------- ----------
Deferred:
Federal 5,425,466 4,647,633 157,434
State 654,247 560,450 18,985
---------- ---------- ----------
6,079,713 5,208,083 176,419
---------- ---------- ----------
$6,979,713 $5,508,083 $ 176,419
========== ========== ==========
</TABLE>
The deferred income tax expense, during the years ended December 31, 1997, 1996,
and 1995 results from the following:
<TABLE>
<CAPTION>
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Type of temporary difference
Alternative minimum tax $ 50,000 $ (250,000) $ --
Depreciation, depletion and amortization (3,051,216) (2,797,220) 32,871
Intangible drilling costs 18,239,155 1,212,361 4,873,778
Sales of properties (5,966,696) 1,424,878 (8,268,363)
Operating loss carryforwards (3,191,530) 5,618,064 3,533,383
------------ ------------ ------------
Deferred tax provision $ 6,079,713 $ 5,208,083 $ 171,669
============ ============ ============
</TABLE>
56
<PAGE> 57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
The components of the net deferred tax liability as of December 31, 1997 and
1996 are as follows:
<TABLE>
<CAPTION>
1997 1996
------------- -------------
<S> <C> <C>
Deferred tax liabilities
Depreciation and basis difference $ 106,017,612 $ 96,901,658
------------- -------------
Deferred tax liability 106,017,612 96,901,658
Deferred tax assets
Tax effect of regular net operating loss 11,962,286 8,770,756
Alternative minimum tax credit 937,000 982,000
Statutory depletion carryforwards 2,320,290 2,320,290
Investment tax credit carryforwards 94,480 168,772
All other -- --
------------- -------------
15,314,056 12,241,818
Valuation allowance (94,480) (168,772)
------------- -------------
Deferred tax assets, net 15,219,576 12,073,046
------------- -------------
Net deferred tax liability $ 90,798,036 $ 84,828,612
============= =============
</TABLE>
In 1996, the Company recorded $58,117,144 of deferred tax liabilities and
$2,027,400 of deferred tax assets in connection with its merger with Tide West.
The effective tax rate during 1997, 1996 and 1995 differs from the statutory
rate of 35% principally because of the effects of state income taxes, net of
federal tax benefit.
The Company has net tax operating loss carryforwards aggregating approximately
$31.4 million available at December 31, 1997, to offset future taxable income.
These carryforwards, if not previously utilized, expire in 2004 through 2011.
Included in these carryforwards are approximately $3.4 million of losses
acquired in the 1996 merger with Tide West. The Company's ability to utilize
these losses is subject to the "ownership change" limitation. The ownership
change rules will limit to approximately $0.8 million annually the amount of
Tide West's losses that can be used.
The Company has an alternative minimum tax ("AMT") credit carryforward of
approximately $937,000. 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 $94,000 which will expire
in 1998 and 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.
57
<PAGE> 58
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
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, 1997, the Company accrued approximately $650,000 for the 1997
contribution to the 401(k) Plan. Contributions to the plans were $417,276 and
$211,596 in 1996 and 1995, respectively.
STOCK OPTION PLAN In 1987, the Company's shareholders approved the 1987 Stock
Incentive Plan (the "1987 Plan") whereby directors, officers, key employees, and
consultants of the Company were entitled to receive incentive stock options,
non-qualified stock options, stock appreciation rights, and restricted stock.
Options granted pursuant to the 1987 Plan were 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. In April 1997, the 1987
Plan expired; however, of the 1.5 million shares of Company stock authorized to
be issued under the 1987 Plan, approximately 824,000 remain outstanding as of
December 31, 1997.
In May 1997, the 1997 Performance and Equity Incentive Plan (the "1997 Plan")
was approved by the Company's stockholders. The 1997 Plan provides for the award
of benefits of various types to salaried employees and directors of the Company
and its affiliates. These include stock options, stock appreciation rights,
restricted shares of Company stock, performance shares, performance-based cash
awards and other performance-based stock awards. One million shares of the
Company's stock are subject to the 1997 Plan. 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 1997, 1996 and
1995. During 1996, the Company implemented SFAS No. 123, Accounting for Stock
Based Compensation. Had compensation cost for these plans been determined
consistent with FAS 123, net of the effect of forfeitures and tax, the Company
would have recorded compensation costs of $298,000, $66,000 and $19,000 in 1997,
1996 and 1995, respectively.
58
<PAGE> 59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
The following table summarizes activity with respect to outstanding stock
options for the years 1997, 1996 and 1995:
<TABLE>
<CAPTION>
Weighted Average
Shares Option Price
------- ----------------
<S> <C> <C>
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
Granted 163,000 14.60
Exercised (40,650) 9.23
Forfeited (7,000) 14.14
------- ---------
Outstanding at December 31, 1997
(635,370 shares exercisable) 888,870 $ 11.39
======= ========
</TABLE>
Of the 888,870 options outstanding at December 31, 1997, 635,370 options are
fully vested and have exercise prices between $6.67 and $25.00, with a weighted
average exercise price of $10.15 and a weighted average remaining contractual
life of 3.1 years. The remaining 253,500 options have exercise prices between
$10.13 and $25, with a weighted average exercise price of $14.51 and a weighted
average remaining contractual life of 6.3 years.
59
<PAGE> 60
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
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 1997, 1996 and 1995, respectively: risk free
interest rates ranging from 5.5% to 5.8%; expected dividend yield of 0%;
expected life of 6 years; expected volatility of 39%, 67% and 67%, respectively.
NOTE 10 - COMMITMENTS AND CONTINGENCIES
ENVIRONMENTAL MATTERS In May 1995, the Company was named by the Environmental
Protection Agency (the "EPA") pursuant to a Resource Conservation and Recovery
Act administrative order as one of two respondents in addition to the
owner/operator of an oilfield production water evaporation facility. The order
requires that work be performed to abate a perceived endangerment to wildlife,
the environment or public welfare. The Company and 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
little as 40%. 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 Company has recorded environmental remediation
liabilities of approximately $1.4 million at December 31, 1997.
LITIGATION
On July 22, 1997, Chenier Exploration, Inc. ("Chenier") brought suit against the
Company in the United States District Court for the Eastern District of Texas
(Chenier Exploration, Inc. v. HS Resources, Inc., Civil Action No. 1:97-CV-399)
seeking damages and certain preliminary relief arising out of the termination of
an Exploration and Development Agreement ("Agreement") between Chenier and the
Company. The Agreement called for, among other things, cooperation between the
companies in the identification and development of oil and gas prospects in the
Gulf Coast regions of Louisiana and Texas. On August 22, 1997, the Court denied
Chenier's requests for preliminary relief and granted the Company's request that
the remaining disputes between Chenier and the Company be resolved in an
arbitration conducted under the auspices of the American Arbitration Association
("AAA") and entitled In re HS Resources, Inc. and Chenier Exploration, Inc., AAA
Arbitration No. 77-180-00171-97.
Chenier asserted that the Company breached express and implied provisions of the
Agreement in connection with its termination of that Agreement, that the Company
acted in bad faith in connection with the Agreement and that the Company
wrongfully interfered with employment and other existing and prospective
agreements involving Chenier in connection with the termination of the
Agreement. The Company denied each of these claims and believed it had
substantial legal defenses to each of the claims, and vigorously defended
against them. These claims were addressed in an arbitration
60
<PAGE> 61
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
hearing which commenced on February 2, 1998, and ended February 17, 1998. For a
discussion of the final decision, see Note 16 of the Notes to Consolidated
Financial Statements.
Additionally, 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 $2,382,498, $1,653,378 and $1,263,930 for December 31, 1997, 1996 and
1995, respectively. Future minimum lease payments as of December 31, 1997 are:
<TABLE>
<CAPTION>
Year Ended December 31,
- ------------------------------------------------------------------
<S> <C>
1998 $ 2,230,770
1999 1,817,336
2000 1,844,635
2001 1,855,767
2002 1,470,347
Thereafter 1,073,839
--------------
Total minimum lease payments $ 10,292,694
==============
</TABLE>
NOTE 11 - OTHER GAS REVENUES
The Company and its subsidiaries continue to enter into transactions designed to
monetize the Company's Section 29 tax credits. In eleven separate transactions,
the first of which was entered into 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. In the fourth quarter of 1997, the Company
received approximately $10.6 million in prepaid tax credits. The Company
recorded the proceeds as deferred revenue and is amortizing the amount to gas
revenues as the gas is produced and the credits are generated. As of December
31, 1997, the Company had amortized approximately $0.7 million of prepaid tax
credits. The Company recognized approximately $4.4 million and $2.7 million of
other gas revenues associated with the tax credits during the years ended
December 31, 1997 and 1996, respectively.
61
<PAGE> 62
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
NOTE 12 - OIL AND GAS ACTIVITIES
MAJOR PURCHASERS In 1997, sales to HSES, Duke Energy Field Service and Amoco
accounted for approximately $31,850,000, $28,704,000 and $23,286,000 or 23.2%,
20.9% and 17.0% of total oil and gas sales, respectively. In 1996, sales to
Amoco 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 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.
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,
1997 1996 1995
------------------ --------------- ---------------
<S> <C> <C> <C>
Property acquisition costs
Unproved $ 131,261,839 $ 35,227,230 $ 4,342,722
Proved $ 167,824,916 $ 338,813,429 $ 25,014,756
------------------ --------------- ---------------
Exploration costs $ 12,856,148 $ 2,100,119 $ 2,747,920
------------------ --------------- ---------------
Development costs $ 46,678,371 $ 37,818,991 $ 29,989,260
------------------ --------------- ---------------
Depreciation, depletion and
amortization $ 51,265,051 $ 40,590,801 $ 25,292,193
------------------ --------------- ---------------
Depreciation, depletion and
amortization per equivalent
unit-of-production $ 5.54 $ 5.33 $ 4.97
================== =============== ===============
</TABLE>
NOTE 13 - 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").
62
<PAGE> 63
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
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.
63
<PAGE> 64
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 1997
<TABLE>
<CAPTION>
ASSETS
Non-
Subsidiary Guarantors Guarantor Elimination
HSR HSRTW Orion Subsidiaries Entries Consolidated
------------- ------------- ------------- -------------- --------------- -------------
<S> <C> <C> <C> <C> <C> <C>
Cash and cash
equivalents $ 3,530,198 $ 159,181 $ -- $ 3,218,329 $ -- $ 6,907,708
Intercompany
receivables 50,135,345 62,297,182 44,082,701 31,757,711 (188,272,939) --
Other current
assets 17,104,097 6,666,991 5,070,687 20,069,162 (1,143,311) 47,767,626
------------- ------------- ------------- ------------ --------------- -------------
Total current
assets 70,769,640 69,123,354 49,153,388 55,045,202 (189,416,250) 54,675,334
------------- ------------- ------------- ------------ --------------- -------------
Oil and gas
properties, net 658,415,237 181,907,170 119,213,794 -- -- 959,536,201
Gas gathering and
transportation
facilities, net -- -- -- 4,540,806 -- 4,540,806
Deferred charges
and other, net 9,935,628 9,058 308,410 1,700 -- 10,254,796
Office and
transportation
equipment and other
property, net 3,140,578 1,344,174 -- 250,354 -- 4,735,106
Investments in
subsidiaries and
other investments 339,641,386 4,023,421 -- 860,288 (343,664,807) 860,288
--------------- ------------- ------------- ------------ --------------- ---------------
Total assets $ 1,081,902,469 $ 256,407,177 $ 168,675,592 $ 60,698,350 $ (533,081,057) $ 1,034,602,531
=============== ============= ============= ============ =============== ===============
LIABILITIES, STOCKHOLDERS' EQUITY AND PARTNERS' CAPITAL
Current liabilities $ 43,210,893 $ 9,418,848 $ 44,184 $ 12,116,491 $ (1,103,313) $ 63,687,103
Current portion of
long-term debt 30,000 -- -- -- -- 30,000
Intercompany payables 138,137,807 4,410,000 35,252,159 10,472,973 (188,272,939) --
Long-term bank
debt and other debt,
net of current portion 412,734,696 -- -- -- -- 412,734,696
9 7/8% subordinated
notes, due 2003 74,653,875 -- -- -- -- 74,653,875
9 1/4% subordinated
notes, due 2006 149,310,413 -- -- -- -- 149,310,413
Other noncurrent
liabilities 20,479,272 -- -- -- -- 20,479,272
Deferred income taxes 19,723,177 61,231,841 2,563,645 7,279,373 -- 90,798,036
Minority interest -- -- -- 23,596 (736,796) (713,200)
Stockholders' equity
and partners'
capital 223,622,336 181,346,488 130,815,604 30,805,917 (342,968,009) 223,622,336
--------------- ------------- ------------- ------------ -------------- ---------------
Total liabilities,
stockholders' equity
and partners' capital $ 1,081,902,469 $ 256,407,177 $ 168,675,592 $ 60,698,350 $ (533,081,057) $ 1,034,602,531
=============== ============= ============= ============ ============== ===============
</TABLE>
64
<PAGE> 65
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
Twelve Months Ended December 31, 1997
<TABLE>
<CAPTION>
Non-
Subsidiary Guarantors Guarantor Elimination
HSR HSRTW Orion Subsidiaries Entries Consolidated
------------ ------------ ------------ ------------- ------------- ------------
<S> <C> <C> <C> <C> <C> <C>
Revenues
Oil and gas sales $ 54,409,889 $ 33,692,171 $ 11,602,694 $ 36,648,062 $ 898,230 $137,251,046
Trading and transportation 4,060,027 16,078,296 -- 108,042,290 (38,118,826) 90,061,787
Other revenues 5,561,898 548,146 -- 538,709 (256,700) 6,392,053
------------ ------------ ------------ ------------ ------------ ------------
Total revenues 64,031,814 50,318,613 11,602,694 145,229,061 (37,477,296) 233,704,886
------------ ------------ ------------ ------------ ------------ ------------
Expenses
Production taxes and lease
operating 11,287,571 8,128,667 3,894,294 11,240,479 -- 34,551,011
Cost of trading and
transportation 4,122,294 15,252,113 -- 106,248,199 (37,220,594) 88,402,012
Depreciation, depletion and
amortization 22,928,530 14,403,058 4,493,234 11,415,965 -- 53,240,787
General and administrative 3,566,995 3,043,262 350,000 1,026,742 -- 7,986,999
Interest 27,378,156 3,712,484 45,817 324,866 (256,702) 31,204,621
------------ ------------ ------------ ------------ ------------ ------------
Total expenses 69,283,546 44,539,584 8,783,345 130,256,251 (37,477,296) 215,385,430
------------ ------------ ------------ ------------ ------------ ------------
Income (loss) before provision
for income taxes (5,251,732) 5,779,029 2,819,349 14,972,810 -- 18,319,456
Provision (benefit) for income
taxes (2,000,910) 2,966,047 1,074,172 4,940,404 -- 6,979,713
------------ ------------ ------------ ------------ ------------ ------------
(3,250,822) 2,812,982 1,745,177 10,032,406 -- 11,339,743
Equity in earnings of
subsidiaries 11,340,759 3,249,806 -- -- (14,590,565) --
------------ ------------ ------------ ------------ ------------ ------------
Net income $ 8,089,937 $ 6,062,788 $ 1,745,177 $ 10,032,406 $(14,590,565) $ 11,339,743
============ ============ ============ ============ ============ ============
</TABLE>
65
<PAGE> 66
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
Twelve Months Ended December 31, 1997
<TABLE>
<CAPTION>
Non-
Subsidiary Guarantors Guarantor Elimination
HSR HSRTW Orion Subsidiaries Entries Consolidated
------------- ------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C>
Cash flows provided by
(used in) operating
activities $ 109,140,819 $ (33,082,135) $ 621,409 $ 17,338,685 $ -- $ 94,018,778
------------- ------------- ------------- ------------- ------------- -------------
Cash flows from investing
activities
Exploration, development
and leasehold costs (57,581,031) (7,807,448) (1,821,454) (7,927,218) -- (75,137,151)
Purchase of proved and
unproved properties (296,070,291) (3,016,464) -- -- -- (299,086,755)
Contributions to
subsidiaries (1,200,045) 18,728,474 -- -- (17,528,429) --
Other 9,989,411 25,661,873 -- 9,354,323 -- 45,005,607
------------- ------------- ------------- ------------- ------------- -------------
Net cash used in
(provided by)
investing
activities (344,861,956) 33,566,435 (1,821,454) 1,427,105 (17,528,429) (329,218,299)
------------- ------------- ------------- ------------- ------------- -------------
Cash flows from financing
activities
Proceeds from debt 337,000,000 -- -- -- -- 337,000,000
Repayments of debt (99,000,000) -- -- -- -- (99,000,000)
Contributions from equity
holders -- -- 1,200,045 (18,728,474) 17,528,429 --
Other (3,878,178) (779,349) -- -- -- (4,657,527)
------------- ------------- ------------- ------------- ------------- -------------
Net cash provided
by (used in)
financing activities 234,121,822 (779,349) 1,200,045 (18,728,474) 17,528,429 233,342,473
------------- ------------- ------------- ------------- ------------- -------------
Net increase (decrease) in
cash and cash equivalents (1,599,315) (295,049) -- 37,316 -- (1,857,048)
Cash and cash equivalents,
beginning of the year 5,129,513 454,230 -- 3,181,013 -- 8,764,756
------------- ------------- ------------- ------------- ------------- -------------
Cash and cash equivalents,
end of the period $ 3,530,198 $ 159,181 $ -- $ 3,218,329 $ -- $ 6,907,708
============= ============= ============= ============= ============= =============
</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.
66
<PAGE> 67
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
NOTE 14 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
OIL AND GAS NET RESERVES The following unaudited tables set forth the estimated
quantities of net proved oil and gas reserves for the Company and the changes in
total proved reserves as of December 31, 1997, 1996 and 1995. All such reserves
are located in the United States. The amounts as of December 31, 1997, 1996 and
1995, 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.
67
<PAGE> 68
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
ANALYSIS OF CHANGES IN PROVED RESERVES
<TABLE>
<CAPTION>
Oil Gas
-----------------------------------
(Thousands of
(Barrels) Cubic Feet)
Proved developed and undeveloped reserves
- --------------------------------------------------------------------------------------
<S> <C> <C>
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
Revision of previous estimates (2,726,993) (36,809,862)
Extensions, discoveries and other additions 2,098,560 42,623,250
Production (2,399,743) (41,125,200)
Purchases of reserves in place 14,839,796 332,793,612
Sales of reserves in place (1,067,900) (62,049,000)
---------- -----------
Balance, December 31, 1997 45,358,100 879,854,100
========== ===========
Proved developed reserves
December 31, 1995 11,557,200 219,262,100
========== ===========
December 31, 1996 23,111,490 508,923,100
========== ===========
December 31, 1997 26,027,500 611,198,400
========== ===========
</TABLE>
68
<PAGE> 69
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,
1997 1996 1995
--------------- --------------- ---------------
<S> <C> <C> <C>
Future cash inflows $ 2,771,498,000 $ 3,045,480,000 $ 857,074,500
Future production costs (681,825,000) (646,925,700) (219,076,680)
Future development costs (360,007,000) (170,708,400) (105,043,800)
--------------- --------------- ---------------
Undiscounted future pre-tax cash flows 1,729,666,000 2,227,845,900 532,954,020
Undiscounted future income taxes (410,680,162) (619,110,885) (129,776,984)
--------------- --------------- ---------------
Undiscounted future pre-tax cash flows,
net of future income taxes 1,318,985,838 1,608,735,015 403,177,036
10% discount factor (689,534,976) (790,717,180) (203,918,587)
--------------- --------------- ---------------
Standardized measure of discounted future net cash flows $ 629,450,862 $ 818,017,835 $ 199,258,449
--------------- --------------- ---------------
Discounted future pre-tax cash flows excluding income taxes $ 822,466,600 $ 1,130,923,000 $ 257,044,900
=============== =============== ===============
</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.
69
<PAGE> 70
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
The following are the principal sources of change in the standardized measure of
discounted future net cash flows:
<TABLE>
<CAPTION>
Year Ended December 31,
1997 1996 1995
------------- ------------- -------------
<S> <C> <C> <C>
Standardized measure of discounted future
net cash flows, beginning of the year $ 818,017,835 $ 199,258,449 $ 194,253,301
Sales and transfers of oil and gas produced,
net of production costs (101,796,457) (80,450,583) (38,528,808)
Sales of reserves in place (63,971,600) (14,892,716) (1,338,530)
Net changes in prices and production costs:
On beginning of year reserves (464,696,728) 281,677,346 3,996,469
On reserves purchased during the year -- 200,295,822 --
Extensions, discoveries and improved recovery,
less related costs 60,509,682 80,749,964 11,194,559
Changes in future development costs (22,474,120) (2,088,801) (14,744,408)
Development costs incurred during the period
that reduced future development costs 43,489,081 32,335,836 33,402,053
Revisions of previous quantity estimates (46,871,761) (1,679,406) (6,918,919)
Purchase of reserves in place 265,063,849 345,252,515 36,213,033
Accretion of discount 113,282,652 25,704,490 23,033,140
Net change in income taxes 121,793,142 (255,118,714) (21,708,352)
Changes in production rates (timing) and other (92,894,713) 6,973,633 (19,595,089)
------------- ------------- -------------
Standardized measure of discounted future
net cash flows, end of the year $ 629,450,862 $ 818,017,835 $ 199,258,449
============= ============= =============
</TABLE>
70
<PAGE> 71
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
$16.38/Bbl of oil and $2.31/Mcf of gas at December 31, 1997, $24.92/Bbl of oil
and $3.39/Mcf of gas at December 31, 1996 and $18.59/Bbl of oil and $1.65/Mcf of
gas at December 31, 1995.
These estimates were determined in accordance with SFAS 69. Because of
unpredictable variances in expenses and capital forecasts, crude oil and gas
price changes, and the fact that the basis for such estimates vary
significantly, management believes that the usefulness of these projections of
cash flow is limited. Estimates of future net cash flows do not represent
management's assessment of future profitability or future cash flow to 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 justifies revisions, either upward or downward, of
reserve estimates. Such adjustments may be material.
71
<PAGE> 72
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
NOTE 15 - QUARTERLY FINANCIAL DATA (UNAUDITED)
The Company's quarterly results of operations are summarized as follows (in
thousands, except per share data):
<TABLE>
<CAPTION>
1997
Mar. 31 June 30 Sept. 30 Dec. 31
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Operating revenues $ 65,959 $ 50,137 $ 49,249 $ 66,417
Operating expenses 49,741 39,639 37,587 49,227
-------- -------- -------- --------
Operating income 16,218 10,498 11,662 17,190
-------- -------- -------- --------
Net income $ 4,367 $ 1,161 $ 1,563 $ 4,249
-------- -------- -------- --------
Diluted earnings per share $ 0.25 $ 0.07 $ 0.09 $ 0.24
======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
1996
Mar. 31 June 30 Sept. 30 Dec. 31
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Operating revenues $ 14,154 $ 26,767 $ 47,566 $ 67,888
Operating expenses 9,999 18,553 36,649 48,721
-------- -------- -------- --------
Operating income 4,155 8,214 10,917 19,167
-------- -------- -------- --------
Net income $ 191 $ 1,645 $ 1,357 $ 5,756
-------- -------- -------- --------
Diluted earnings per share 0.02 $ 0.14 $ 0.08 $ 0.33
======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
1995
Mar. 31 June 30 Sept. 30 Dec. 31
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Operating revenues $ 15,737 $ 14,810 $ 11,921 $ 12,709
Operating expenses 11,204 10,982 9,131 9,279
-------- -------- -------- --------
Operating income 4,533 3,828 2,790 3,430
-------- -------- -------- --------
Net income (loss) $ 640 $ 180 $ (383) $ (163)
-------- -------- -------- --------
Diluted earnings per share $ 0.06 $ 0.02 $ (0.03) $ (0.01)
======== ======== ======== ========
</TABLE>
NOTE 16 - SUBSEQUENT EVENT (UNAUDITED)
On March 26, 1998, the arbitrator in the Chenier litigation (See Note 10) issued
a final award in favor of the Company denying each of Chenier's claims for
damages.
72
<PAGE> 73
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,
1997 and 1996, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1997. 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, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Denver, Colorado
February 20, 1998
73
<PAGE> 74
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.
74
<PAGE> 75
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 1987 Stock Incentive Plan, as amended December 2, 1996. (Incorporated
by reference to Exhibit 10.5 to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 1997, filed May 15, 1997.)
10.2 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.)
10.3 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.)
10.4 1992 Directors' Stock Option Plan. (Incorporated by reference to
Exhibit 10.10 to Amendment No. 1 to the Company's Registration
Statement on Form S-1, No. 33-52774, filed November 9, 1992.)
10.4.1 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.))
10.5 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.)
75
<PAGE> 76
10.6 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.))
10.7 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.)
10.8 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.)
10.9 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.)
10.10 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.)
10.11 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.)
10.12 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.)
10.13 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.)
10.14 Purchase and Sale Agreement dated March 25, 1996, between Orion, the
Company and Wattenberg Resources Land, L.L.C. (Incorporated by
reference to Exhibit 10.28 to the Company's Quarterly Report on Form
10-Q for the quarter ended March 31, 1996, filed May 15, 1996.)
10.15 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.)
10.16 Amended and Restated Credit Agreement dated as of June 14, 1996,
among the Company, Chase as agent, and the Banks signatory thereto.
(Incorporated by reference to Exhibit 10.21 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
filed August 14, 1996.)
76
<PAGE> 77
10.17 First Amendment to Amended and Restated Credit Agreement dated as of
June 17, 1996, by and among the Company and Chase in its individual
capacity and as agent for the Lenders. (Incorporated by reference to
Exhibit 10.22 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
10.18 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.)
10.19 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
Exhibit 10.23 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
10.20 Guaranty Agreement by HSR Acquisition, Inc. in favor of Chase, as
Agent, dated June 14, 1996. (Incorporated by reference to Exhibit
10.24 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1996, filed August 14, 1996.)
10.21 Guaranty Agreement by Orion in favor of Chase, as Agent, dated June
14, 1996. (Incorporated by reference to Exhibit 10.25 to the
Company's Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, filed August 14, 1996.)
10.22 First Amendment to Guaranty Agreement dated as of June 17, 1996, by
and among Orion and Chase, in its individual capacity and as agent
for the Lenders. (Incorporated by reference to Exhibit 10.26 to the
Company's Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, filed August 14, 1996.)
10.23 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 Exhibit 10.27 to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1996, filed August 14,
1996.)
10.24 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 Exhibit 10.28 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
filed August 14, 1996.)
10.25 Hedging Agreement between Chase and the Company dated May 1, 1996.
(Incorporated by reference to Exhibit 10.29 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
filed August 14, 1996.)
10.26 Hedging Agreement between Chase and the Company dated May 1, 1996.
(Incorporated by reference to Exhibit 10.30 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
filed August 14, 1996.)
77
<PAGE> 78
10.27 Hedging Agreement between Chase and the Company dated June 1, 1996.
(Incorporated by reference to Exhibit 10.31 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
filed August 14, 1996.)
10.28 Purchase and Sale Agreement between the Company and Wattenberg Gas
Investments, LLC dated April 25, 1996. (Incorporated by reference to
Exhibit 10.32 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
10.29 Purchase and Sale Agreement between Wattenberg Resources Land L.L.C.
and Wattenberg Gas Investments, LLC dated May 21, 1996. (Incorporated
by reference to Exhibit 10.33 to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1996, filed August 14,
1996.)
10.30 Purchase and Sale Agreement between Orion and Wattenberg Gas
Investments, LLC dated June 14, 1996. (Incorporated by reference to
Exhibit 10.34 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
10.31 Purchase and Sale Agreement between Wattenberg Resources Land L.L.C.
and Wattenberg Gas Investments, LLC dated June 14, 1996.
(Incorporated by reference to Exhibit 10.35 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,
filed August 14, 1996.)
10.32 Purchase and Sale Agreement between Orion and Wattenberg Gas
Investments, LLC dated June 14, 1996. (Incorporated by reference to
Exhibit 10.36 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
10.33 Purchase and Sale Agreement between the Company and Wattenberg Gas
Investments, LLC dated June 28, 1996. (Incorporated by reference to
Exhibit 10.37 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
10.34 Purchase and Sale Agreement between HSRTW, Inc. and WestTide
Investments, LLC dated August 9, 1996. (Incorporated by reference to
Exhibit 10.37 to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1996, filed November 7, 1996.)
10.35 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 Exhibit 10.38 to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30,
1996, filed November 7, 1996.)
10.36 Purchase Agreement dated November 27, 1996, among the Company, Orion,
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.)
10.37 Registration Agreement dated November 27, 1996, among the Company,
Orion, 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.)
78
<PAGE> 79
10.38 Employment Agreement between James Piccone and the Company dated
April 21, 1995. (Incorporated by reference to Exhibit 10.42 to the
Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 1996, filed March 18, 1997 (as amended by Form 10-K/A-1
on March 20, 1997.))
10.39 Purchase and Sale Agreement dated June 30, 1997 among HSRTW, Inc. and
Horizon Gas Partners, L.P. as Seller and Gothic Energy Corporation as
Buyer. (Incorporated by reference to Exhibit 10.43 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 1997,
filed August 14, 1997.)
10.40 Amended Purchase and Sale Agreement dated as of July 16, 1997, among
HSRTW, Inc. and Horizon Gas Partners, L.P. as Seller and Gothic
Energy Corporation as Buyer. (Incorporated by reference to Exhibit
10.44 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1997, filed August 14, 1997.)
10.41 1997 Performance and Equity Incentive Plan. (Incorporated by
reference to Exhibit A to the Company's Definitive Proxy Statement
for its Annual Meeting of Stockholders held on May 22, 1997, filed
April 24, 1997.)
10.42 Purchase and Sale Agreement between the Company and Amoco Production
Company dated November 25, 1997. (Incorporated by reference to
Exhibit 10.1 to the Company's Current Report on Form 8-K, filed
December 23, 1997.)
10.43 Side Letter Agreement between the Company and Amoco Production
Company dated November 25, 1997. (Incorporated by reference to
Exhibit 10.2 to the Company's Current Report on Form 8-K, filed
December 23, 1997.)
10.44 Closing Side Agreement between the Company and Amoco Production
Company dated December 15, 1997. (Incorporated by reference to
Exhibit 10.3 to the Company's Current Report on Form 8-K, filed
December 23, 1997.)
10.45 Third Amendment to Amended and Restated Credit Agreement dated as of
December 15, 1997, among the Company and The Chase Manhattan Bank as
agent for the Lenders signatory thereto. (Incorporated by reference
to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed
December 23, 1997.)
10.46* Purchase and Sale Agreement dated December 15, 1997, by and between
HS Resources, Inc. as Seller and WestTide Investments, LLC as Buyer.
23.1* Consent of Arthur Andersen LLP
23.2* Consent of Williamson Petroleum Consultants, Inc.
23.3* Consent of Netherland, Sewell & Associates, Inc.
27* Financial Data Schedule
- -------------------------
* Filed herewith
79
<PAGE> 80
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 31st 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
31st 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
80
<PAGE> 81
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<S> <C>
10.46 Purchase and Sale Agreement dated December 15, 1997 by and
between HS Resources, Inc. as Seller and WestTide Investments,
LLC as Buyer.
23.1 Consent of Arthur Andersen LLP
23.2 Consent of Williamson Petroleum Consultants, Inc.
23.3 Consent of Netherland, Sewell & Associates, Inc.
27 Financial Data Schedule
</TABLE>
81
<PAGE> 1
================================================================================
PURCHASE AND SALE AGREEMENT
[DIRECT PACKAGE]
BETWEEN
HS RESOURCES, INC.
AND
WESTTIDE INVESTMENTS, LLC
DATED: DECEMBER 15, 1997
================================================================================
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C> <C>
1. Advance and Purchase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.1 Advance of Funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2 Purchase and Sale of Rights under Amoco Agreement . . . . . . . . . . . . . . . . . . . . . . . 1
2. The Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
2.1 Leases and Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
2.2 Incidental Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
3. Effective Date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
4. Tax Credit Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
5. Apportionment of Production, Revenues, Taxes and other Expenses . . . . . . . . . . . . . . . . . . . . . 4
6. Buyer's Representations and Warranties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
6.1 Existence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
6.2 Power and Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
6.3 Authorization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
6.4 Execution and Delivery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
6.5 Securities Laws . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
6.6 Brokers' Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
7. Seller's Representations and Warranties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
7.1 Existence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
7.2 Power and Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
7.3 Authorization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
7.4 Execution and Delivery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
7.5 Brokers' Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
7.6 Reserve Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
7.7 Liens . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
7.8 Title . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
7.9 Preferential Purchase Rights and Consents . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
7.10 No Prepayments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
7.11 Gas Balancing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
7.12 Leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
7.13 Operations in Progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
7.14 Hydrocarbon Sales Contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
7.15 Proceeds of Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
7.16 Material Contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
7.17 Bills in the Ordinary Course . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
7.18 Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
7.19 Compliance with Laws . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
7.20 Environmental Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
7.21 Payment of Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
</TABLE>
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<PAGE> 3
<TABLE>
<S> <C> <C>
7.22 Tax Partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
7.23 Other Tax Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
8. Certain Tax Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
8.1 Opinion of Tax Counsel, Right to Request Ruling . . . . . . . . . . . . . . . . . . . . . . . . 12
8.2 Tax Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
8.3 Escrow in the Event of Tax Audit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
8.4 Settlements Resulting from a Tax Audit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
9. Covenants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
9.1 Cooperation and Access . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
9.2 Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
10. Closing Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
10.1 Seller's Closing Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
10.2 Buyer's Closing Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
11. Closing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
11.1 Advance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
11.2 Section 15.2 Payment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
11.3 Notice of Preferential Rights and Consents . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
11.4 Assignments; Recourse Note; Option . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
11.5 Non-Foreign Ownership Affidavits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
11.6 Evidence of Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
11.7 Contribution Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
11.8 Guaranty Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
11.9 Seller's Officer's Certificate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
11.10 Opinion on Behalf of Seller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
11.11 Buyer's Manager's Certificate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
11.12 Opinion on Behalf of Buyer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
11.13 Management Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
11.14 Performance Power of Attorney . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
11.15 Tax Opinion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
11.16 Additional Instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
12. Post-Closing Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
12.1 Files and Records . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
12.2 Sales Taxes and Recording Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
12.3 Rebates for Defective Interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
12.4 Rebates for Exercised Preferential Purchase Rights, Failure to Obtain Consents . . . . . . . . . 18
12.5 Reconveyance of Excluded Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
12.6 Allocation of Commingled Production and Costs . . . . . . . . . . . . . . . . . . . . . . . . . 18
12.7 Performance of Buyer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
12.8 Overpayments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
13. Apportionment of Liabilities and Obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
</TABLE>
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<PAGE> 4
<TABLE>
<S> <C> <C>
13.1 Buyer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
13.2 Seller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
14. Indemnification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
14.1 Buyer's Indemnification of Seller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
14.2 Seller's Indemnification of Buyer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
14.3 Third Party Claims . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
15. Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
15.1 Further Assurances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
15.2 Expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
15.3 Notices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
15.4 Survival . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
15.5 Confidentiality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
15.6 Announcements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
15.7 Assignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
15.8 Binding Effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
15.9 Complete Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
15.10 Knowledge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
15.11 Governing Law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
15.12 Counterparts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
</TABLE>
(iii)
<PAGE> 5
EXHIBITS
<TABLE>
<S> <C>
Exhibit A Leases (Colorado)
Exhibit B Wells (showing WI, NRI, qualifying formations)
Exhibit C Form of Wellbore Assignment of Oil and Gas Leases
Exhibit D Form of Assignment of Production Payment and Future
Interest (with Form of Recourse Promissory Note)
Exhibit E Form of Option to Purchase Oil and Gas Interests
Exhibit F Reserve Report
Exhibit G Preferential Purchase Rights and Consents
Exhibit H Prepayments and Gas Imbalances
Exhibit I Operations in Progress
Exhibit J Hydrocarbon Sales Contracts
Exhibit K Legal Proceedings
Exhibit L Tax Partnerships
Exhibit M Well List - No NGPA Certification Received
Part I - Uphole Recompletions
Part II - Wells Timely Drilled
Exhibit N Form of Non-Foreign Ownership Affidavits
Exhibit O Form of Contribution Agreement and Form of Guaranty Agreement
Exhibit P Form of Seller's Officer's Certificate
Exhibit Q Form of Opinion on Behalf of Seller
Exhibit R Form of Buyer's Manager's Certificate
Exhibit S Form of Opinion on Behalf of Buyer
Exhibit T Form of Management Agreement
Exhibit U Form of Escrow Agreement
Exhibit V Form of Limited Power of Attorney
</TABLE>
(iv)
<PAGE> 6
PURCHASE AND SALE AGREEMENT
This Purchase and Sale Agreement [Direct Package] (this "Agreement"),
dated December 15, 1997, is between HS Resources, Inc., a Delaware corporation
("Seller" or "HSR") and WestTide Investments, LLC, a Delaware limited liability
company ("Buyer" or "WestTide").
RECITALS
A. Pursuant to that certain Purchase and Sale Agreement dated
November 25, 1997 between Amoco Production Company ("Amoco") and Seller (the
"Amoco Agreement"), Seller is the owner of the right to acquire certain oil and
gas leasehold interests in Colorado, as more specifically described below in
Section 2 (the "Assets").
B. Seller desires to sell its right to acquire the Assets, and
Seller is willing to advance to Buyer a portion of the funds required to
purchase the Assets from Amoco.
C. Seller and Buyer are parties to that certain Acquisition and
Nominee Agreement dated December 15, 1997 (the "Nominee Agreement"), wherein
Seller will acquire and hold record title to the Assets for and on behalf of
Buyer as Buyer's nominee.
D. Buyer desires to purchase the Assets subject to the obligation
to repay the advance from Seller and the terms and conditions of the Nominee
Agreement and this Agreement.
AGREEMENT
IN CONSIDERATION of the mutual benefits contemplated herein and other
good and valuable consideration, the receipt and sufficiency of which are
hereby acknowledged, Seller and Buyer agree as follows:
1. Advance and Purchase.
1.1 Advance of Funds. Seller agrees to advance to Buyer
a portion of the funds required to purchase the Assets from Amoco. At Closing,
Seller shall make a cash advance to Buyer in the amount of $57,633,009 (the
"Advance"). In consideration for the Advance, Buyer shall convey to Seller a
junior net profits production payment in the Assets (the "Production Payment"),
and a senior recourse promissory note (the "Recourse Note") as set forth in the
Assignment of Production Payment and Future Interest in a form substantially
similar to Exhibit D (the "Production Payment Assignment"). Buyer will make
the proceeds of the Advance, as well as other funds, available to Seller as
Buyer's nominee under the Nominee Agreement to acquire the Assets on behalf of
Buyer under the Amoco Agreement.
1.2 Purchase and Sale of Rights under Amoco Agreement.
In consideration for Buyer (i) conveying to Seller (a) a future interest in the
Assets (the "Future Interest") as set forth in the Production Payment
Assignment, and (b) the Option To Purchase Oil and Gas
<PAGE> 7
Interests in a form substantially similar to Exhibit E (the "Option"); and (ii)
agreeing to pay to Seller in the future the Credit Payment Amounts set forth
below in Section 4, Seller agrees to convey its right under the Amoco Agreement
to acquire the Assets to Buyer and Buyer agrees to purchase the Assets, all
pursuant to the terms and conditions of this Agreement, the Nominee Agreement
and the Wellbore Assignment of Oil and Gas Leases in a form substantially
similar to Exhibit C (the "Wellbore Assignment"). As between Buyer and Seller
under this Agreement, the portion of the purchase price under the Amoco
Agreement allocated to the Assets shall be $67,392,009.
2. The Assets. The "Assets" shall be all of the following:
2.1 Leases and Wells. Seller's right, title and interest
in and to the oil and gas leases and mineral interests described in Exhibit A,
including any and all overriding royalty interests owned by Seller in such
leases, but insofar and only insofar as said leases and interests cover the
right to receive proceeds of production from the wells described in Exhibit B
from the intervals referenced in Section 7.23 and identified in Exhibit B in
such wells as of the Effective Date (the above described interest in such
leases being herein called the "Leases" and the above described interest in
such wells being herein called the "Wells"), and subject to any restrictions,
exceptions, reservations, conditions, limitations, burdens, contracts,
agreements and other matters applicable to such Leases and Wells.
2.2 Incidental Rights. All of Seller's right, title and
interest in and to the following insofar and only insofar as same are
attributable to the Leases and the Wells:
(a) Unitization and Pooling Agreements. All
presently existing and valid oil, gas or mineral unitization, pooling,
operating and communitization agreements, declarations and orders
affecting the Leases and Wells, and in and to the properties covered
and the units created thereby;
(b) Personal Property. The personal property
and fixtures that are appurtenant to the Wells, including all wells,
casing, tubing, pumps, separators, tanks, lines and other personal
property and oil field equipment appurtenant to such Wells;
(c) Agreements. All presently existing and
valid oil and gas sales, purchase, production swap, gathering and
processing contracts and operating agreements, joint venture
agreements, partnership agreements, rights-of-way, easements, permits,
surface leases and other contracts, agreements and instruments, but
specifically excluding any management agreements.
Seller shall remain co-owner of any "Agreements," "Personal Property" and
"Unitization and Pooling Agreements" to the extent they pertain to any property
or formation owned by Seller that is not exclusively part of the Wells.
3. Effective Date. The purchase and sale of the Assets shall be
effective, for all purposes, including allocation of revenue, expenses and
taxes, as of December 15, 1997 at 7:00 a.m. local time at the site of the
Assets (the "Effective Date").
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<PAGE> 8
4. Tax Credit Payments. Following the Effective Date, Buyer
shall pay to Seller the Credit Payment Amounts. "Credit Payment Amount" shall
mean, for any Payment Period, an amount equal to $0.70 of each dollar of tax
credits (the "Tax Credits") available to Buyer under Section 29 of the
Internal Revenue Code of 1986, as amended (the "IRC"), as a result of the sale
of Subject Hydrocarbons by or on behalf of Buyer, to the extent that such
Subject Hydrocarbons (i) constitute "qualified fuels" within the meaning of IRC
Section 29(c), (ii) meet the requirements of IRC Sections 29(d)(1), 29(d)(4)
and 29(f), during (x) such Payment Period and (y) any earlier Payment Period to
the extent the dollar amount of Tax Credits attributable thereto was not taken
into account in a Credit Payment Amount for a previous Payment Period, and
(iii) are produced from the Wells. For purposes of the preceding sentence, Tax
Credits available to Buyer under IRC Section 29 shall be determined after
taking into account any phase-out of Tax Credits under IRC Section 29(b)(1)
and any applicable inflation adjustment under IRC Section 29(b)(2), but shall
be determined without regard to limitations on Buyer's or its affiliate's use
of Tax Credits imposed by IRC Section 29(b)(6) and without regard to whether
Buyer or its affiliates actually utilize such Tax Credits. The Credit Payment
Amount for any given Payment Period shall initially be based on estimated
Subject Hydrocarbon production and sales data available at the time of the
calculation of such amount and later corrected when actual data is available.
The Credit Payment Amount shall be determined on the assumption that (i) the
Production Payment is treated as a production payment for federal income tax
purposes, (ii) Buyer is treated as owning the economic interest in minerals in
place in the Assets, and (iii) the Recourse Note is treated as debt for federal
income tax purposes. Credit Payment Amounts shall be calculated and, unless
otherwise provided herein, will be due and payable within fifteen (15) days of
Buyer's receipt (by overnight courier or facsimile) of an invoice for payment
(except as provided below in this Section 4) with respect to gas produced and
sold from December 15, 1997 until the earlier of (x) the aggregate of all
Credit Payment Amounts computed pursuant to this Agreement equals $12,700,000
(subject to the provisions of Paragraph 1.a.(vii) of the Option), (y) December
31, 2002, or (z) the first day on which Tax Credits are no longer permitted for
gas attributable to the Subject Hydrocarbons and produced and sold from the
Wells. If for any reason the Tax Credits are repealed by Congressional statute
or resulting regulation, no Credit Payment Amount shall be due with respect to
Subject Hydrocarbons subject to such repeal. If for any reason the amount of
Tax Credits contemplated under this Agreement are reduced by Congressional
statute or resulting regulation, the Credit Payment Amounts due under this
Agreement shall be reduced commensurate with such reduction in Tax Credits.
For purposes of the foregoing, the terms "Subject Hydrocarbons" and "Payment
Period" shall have the meanings set forth in the Production Payment Assignment.
Notwithstanding any of the provisions of the preceding paragraph in
this Section 4, Buyer shall have no obligation to pay the first $6,562,000 in
Credit Payment Amounts determined in accordance with the preceding paragraph
(the "Credit Threshold"). If the Credit Threshold exceeds the aggregate of
actual Credit Payment Amounts determined under the preceding paragraph as of
December 31, 2002, Buyer shall be treated as having made an overpayment of
Credit Payment Amounts in an amount equal to such excess and such excess shall
be paid by Seller to Buyer on or before February 1, 2003. Buyer shall not have
any right to require or cause an acceleration or recoupment of any such excess
prior to January 1, 2003. If Seller exercises the Option with respect to
twenty-five percent (25%) or more, in the aggregate, of the reserves
-3-
<PAGE> 9
attributable to the Assets at any time prior to January 1, 2003, then Seller
shall pay to Buyer an amount, if any, equal to the excess of the Credit
Threshold over the aggregate of actual Credit Payment Amounts determined under
the preceding paragraph as of the effective date the Option is exercised.
5. Apportionment of Production, Revenues, Taxes and other
Expenses. Buyer shall be entitled to revenue from the sale of hydrocarbons
produced from the Wells on or after the Effective Date, subject to the
Production Payment, Future Interest and the Option. Buyer shall pay for costs
and expenses incurred with respect to the Assets on or after the Effective
Date. Seller shall be entitled to revenue from the sale of hydrocarbons
produced from the Wells before the Effective Date, and shall pay for costs and
expenses incurred with respect to the Assets prior to the Effective Date.
Taxes relating to the Assets, including ad valorem, property, production,
severance and other taxes (other than income taxes) shall be allocated in the
same manner as other expenses. Taxes that are measured by or that relate to
production shall be treated as expenses in connection with such production
regardless of the period for which such taxes are assessed.
6. Buyer's Representations and Warranties. Buyer makes the
following representations and warranties as of the date of execution of this
Agreement:
6.1 Existence. Buyer is a limited liability company,
duly organized, validly existing and formed under the law of the State of
Delaware, and Buyer is duly qualified to carry on its business, and is duly
qualified and in good standing, in each of the states in which the nature of
its business and activities requires it to be so qualified.
6.2 Power and Authority. Buyer has all requisite power
and authority to carry on its business as presently conducted, to enter into
this Agreement and each of the documents contemplated to be executed by Buyer
at Closing, and to perform its obligations under this Agreement and under such
documents. The consummation of the transactions contemplated by this Agreement
and each of the documents contemplated to be executed by Buyer at Closing will
not violate, nor be in conflict with, (i) any provision of Buyer's
organizational or governing documents, (ii) any material agreement or
instrument to which Buyer is a party or is bound, or (iii) any judgment,
decree, order, statute, rule or regulation applicable to Buyer.
6.3 Authorization. The execution, delivery and
performance of this Agreement and each of the documents contemplated to be
executed by Buyer at Closing and the transactions contemplated hereby and
thereby have been duly and validly authorized by all requisite action on the
part of Buyer.
6.4 Execution and Delivery. This Agreement has been duly
executed and delivered on behalf of Buyer, and at the Closing all documents,
instruments and schedules required hereunder to be executed and delivered by
Buyer shall have been duly executed and delivered. This Agreement does, and
such documents and instruments shall, constitute legal, valid and binding
obligations of Buyer enforceable in accordance with their terms, subject to (i)
applicable bankruptcy, insolvency, reorganization, moratorium and other similar
laws of
-4-
<PAGE> 10
general application with respect to creditors, (ii) general principles of
equity and (iii) the power of a court to deny enforcement of remedies generally
based upon public policy.
6.5 Securities Laws. Buyer is purchasing the Assets for
Buyer's own account, not for public distribution thereof, and Buyer shall not
sell or transfer all or any part of, or any interest in, the Assets in
violation of the Securities Act of 1933, as amended, and the rules and
regulations thereunder, or the securities laws of any state.
6.6 Brokers' Fees. Buyer has incurred no liability,
contingent or otherwise, for brokers' or finders' fees relating to the
transactions contemplated by this Agreement for which Seller shall have any
responsibility whatsoever.
7. Seller's Representations and Warranties. Seller makes the
following representations and warranties as of the date of this Agreement:
7.1 Existence. Seller is a corporation duly organized
and validly existing under the law of the State of Delaware, and Seller is duly
qualified to carry on its business, and is in good standing in the States of
Delaware and Colorado.
7.2 Power and Authority. Seller has all requisite
authority to carry on its business as presently conducted, to enter into this
Agreement and each of the documents contemplated to be executed by Seller at
Closing, and to perform its obligations under this Agreement and under such
documents. The consummation of the transactions contemplated by this Agreement
and each of the documents contemplated to be executed by Seller at Closing will
not violate, nor be in conflict with, (i) any provision of Seller's Certificate
of Incorporation, bylaws or other governing documents, (ii) any material
agreement or instrument to which Seller is a party or is bound, or (iii) any
judgment, decree, order, statute, rule or regulation applicable to Seller;
provided that, the representations and warranties contained in clauses (ii) and
(iii) of this Section 7.2 are subject to (a) consents of or filings with the
United States Department of Interior or the applicable state agencies or
authorities in connection with the assignment of any federal or state leases or
any interest therein to the extent such consents are typically received or
filings typically made subsequent to such assignment ("Governmental Consents"),
(b) preferential rights to purchase all or any portion of the Assets and
consent to or notices of assignment necessary to convey all or any portion of
the Assets which are not Governmental Consents, and (c) any violation of any
maintenance of uniform interest provision in any applicable operating
agreement.
7.3 Authorization. The execution, delivery and
performance of this Agreement and each of the documents contemplated to be
executed by Seller at Closing and the transactions contemplated hereby and
thereby have been duly and validly authorized by all requisite corporate action
on the part of Seller.
7.4 Execution and Delivery. This Agreement has been duly
executed and delivered on behalf of Seller, and at the Closing all documents,
instruments and schedules required hereunder to be executed and delivered by
Seller will be duly executed and delivered. This Agreement does, and such
documents and instruments shall, constitute legal, valid and
-5-
<PAGE> 11
binding obligations of Seller enforceable in accordance with their terms,
subject to (i) applicable bankruptcy, insolvency, reorganization, moratorium
and other similar laws of general application with respect to creditors, (ii)
general principles of equity and (iii) the power of a court to deny enforcement
of remedies generally based upon public policy.
7.5 Brokers' Fees. Seller has incurred no liability,
contingent or otherwise, for brokers' or finders' fees relating to the
transactions contemplated by this Agreement for which Buyer shall have any
responsibility whatsoever.
7.6 Reserve Report. The term "Reserve Report" shall mean
the reserve report prepared by Seller which is based on reserves as of December
31, 1996, and attached hereto as Exhibit F. To Seller's best knowledge, the
average price for sales of hydrocarbons (based on contract prices for existing
effective contracts and estimates of regional spot prices adjusted for regional
transportation costs), historical costs of operations, production volumes, and
payout data used by Seller in the preparation of the Reserve Report were, on
the dates so used, accurate in all material respects.
7.7 Liens. Except for the burdens and obligations
created by or arising under the Leases and except for Permitted Encumbrances,
the Assets are free and clear of all Encumbrances. As used herein, the term
"Encumbrances" shall mean all royalties, overriding royalties, production
payments, debts, liens, mortgages, security interests, and encumbrances. As
used herein, the term "Permitted Encumbrances" shall mean the following:
(i) the burdens, encumbrances and obligations
created by or arising under the Wells and other agreements affecting
the Assets, and all royalties, overriding royalties, net profits
interests, carried interests, reversionary interests, back-in rights
and other burdens taken into account in computing the net revenue
interests ("NRI") and working interests ("WI") set forth on Exhibit B
for the Wells;
(ii) all rights to consent by, required notices
to, filings with, or other actions by governmental entities in
connection with the sale or conveyance of the Assets if the same are
customarily obtained subsequent to such sale or conveyance;
(iii) rights of reassignment upon surrender of the
Leases held by predecessors in interest to Seller;
(iv) easements, rights-of-way, servitudes,
permits, licenses, surface leases and other rights in respect of
surface use to the extent these do not materially interfere with
operations or production on or from the Assets;
(v) rights and regulatory powers reserved to or
vested in any municipality or governmental, statutory or public
authority;
(vi) all Material Contracts to the extent same do
not reduce Seller's interest in the production from the Wells to less
than the NRI set forth on Exhibit B;
-6-
<PAGE> 12
(vii) any (a) undetermined or inchoate liens or
charges constituting or securing the payment of expenses which were
incurred incidental to maintenance, development, production or
operation of the Assets or for the purpose of developing, producing or
processing oil, gas or other hydrocarbons therefrom or therein and (b)
materialman's, mechanics', repairman's, employees', contractors',
operators' or other similar liens, security interests or charges for
liquidated amounts arising in the ordinary course of business
incidental to construction, maintenance, development, production or
operation of the Assets or the production or processing of oil, gas or
other hydrocarbons therefrom, that are not delinquent and that will be
paid in the ordinary course of business or, if delinquent, that are
being contested in good faith;
(viii) any liens for taxes not yet delinquent or, if
delinquent, that are being contested in good faith in the ordinary
course of business;
(ix) any liens or security interests created by
law or reserved in Leases for royalty, bonus or rental or for
compliance with the terms of the Leases;
(x) any prohibitions or restrictions similar to
the Maintenance of Uniform Interest Provisions contained in Article
VIII.D. of the A.A.P.L. Form 610-1982 Model Form Operating Agreement
and any contribution obligations under provisions similar to Article
VII.B of such Model Form Operating Agreement;
(xi) all preferential rights to purchase all or
any portion of the Assets and consents to or notices of assignment
necessary to convey all or any portion of the Assets which are not
described in item (ii) of this definition of Permitted Encumbrances;
(xii) all agreements and obligations relating to
imbalances with respect to the production, transportation or
processing of gas or calls or purchase options on oil or gas
production;
(xiii) all agreements and obligations relating to
gathering, transportation or processing of gas or oil production;
(xiv) all treating, processing, sales or marketing
agreements which have a fee which is based on a percentage of proceeds
or an obligation to transfer certain volumes of gas or oil production
in- kind;
(xv) all obligations by virtue of a prepayment,
advance payment or similar arrangement under any contract for the sale
of gas production, including by virtue of "take or pay" or similar
provisions, to deliver gas produced from or attributable to the Wells
after the Effective Date without then or thereafter being entitled to
receive full payment therefor;
(xvi) all liens, charges, encumbrances, contracts,
agreements, instruments, obligations, defects, irregularities and
other matters affecting any Asset
-7-
<PAGE> 13
which individually or in the aggregate will not interfere materially
with the operation, value or use of such Asset;
(xvii) the burdens, encumbrances and obligations
created by or arising under this Agreement, the Wellbore Assignment,
Production Payment Assignment, Option or Management Agreement; and
(xviii) all matters identified as "Permitted
Encumbrances" under the Amoco Agreement.
7.8 Title. Subject to Seller's right to bring claims
against Amoco for a period of 120 days following the Closing Date based upon
Seller's due diligence evaluations pursuant to Section 4.2 of the Amoco
Agreement, Buyer will receive Defensible Title to the Assets. The term
"Defensible Title" means such title to the Leases that, subject to and except
for the Permitted Encumbrances and the terms of the Amoco Agreement, entitles
Buyer to receive an interest in production from the Wells not less than the
respective NRIs in the Wells as set forth on Exhibit B, and entitles Buyer to
own the respective WIs in the Wells as set forth on Exhibit B under applicable
state law and for federal income tax purposes. Any Well or Lease for which
there is less than Defensible Title as of the date of this Agreement shall be
called a "Defective Interest." Buyer's exclusive remedy for Seller's breach of
this representation and warranty is set forth in Section 12.3. Buyer and
Seller shall cooperate fully and consult in good faith with each other in the
litigation of any matter identified in this Section 7.8
7.9 Preferential Purchase Rights and Consents. To
Seller's best knowledge, except as set forth in Exhibit G and subject to
Seller's rights under Sections 3.4 and 3.5 of the Amoco Agreement, there do not
exist any preferential rights to purchase all or any portion of the Assets. To
Seller's best knowledge, except for Governmental Consents and other matters as
set forth in Exhibit G, there are no consents or waivers necessary to convey
any material portion of the Assets pursuant to this Agreement. Buyer's
exclusive remedy for Seller's breach of this representation and warranty is set
forth in Section 12.4.
7.10 No Prepayments. To Seller's best knowledge, except
as set forth in Exhibit H, there is no obligation, by virtue of a prepayment
arrangement, a "take or pay" arrangement, a production payment, hedging or any
other arrangement, to deliver any material portion of hydrocarbons produced
from the Wells at some future time without then or thereafter receiving full
payment therefor.
7.11 Gas Balancing. To Seller's best knowledge, except as
set forth in Exhibit H and subject to Seller's right to bring claims against
Amoco for a period of 120 days following the Closing Date based upon Seller's
due diligence evaluations pursuant to Section 4.4 of the Amoco Agreement, no
material portion of hydrocarbons produced from the Wells are subject to a gas
imbalance or other arrangement requiring delivery of hydrocarbons after the
Effective Date without receiving full payment therefor.
7.12 Leases. To Seller's best knowledge, all royalties,
rentals and other payments due under the Leases have been properly and timely
paid except where the failure to
-8-
<PAGE> 14
pay same will not have a material adverse effect on the value of the particular
Asset. To Seller's best knowledge, subject to Seller's right to bring claims
against Amoco for a period of 120 days following the Closing Date based upon
Seller's due diligence evaluations pursuant to Section 4.2 of the Amoco
Agreement, all Leases are presently in full force and effect, and no written
notice of material default under any Lease has been received that could result
in cancellation of the Lease. Any Lease which is not presently in full force
and effect, or for which all royalties, rentals or other payments due have not
been paid, or for which the lessee thereunder is in material default as of the
date of this Agreement shall be treated as a Defective Interest. Buyer's
exclusive remedy for Seller's breach of this representation and warranty is set
forth in Section 12.3.
7.13 Operations in Progress. Except for operations
disclosed on Exhibit I and normal daily operating expenses, as of the date of
this Agreement there are no operations in progress with respect to the Assets
which are reasonably expected to exceed $35,000 in cost net to Buyer's interest
and which shall be payable in whole or in part on or after the Effective Date.
7.14 Hydrocarbon Sales Contracts. Except as specifically
indicated in Exhibit J and for calls on production, options to purchase or
similar rights with respect to production from the Wells, no material portion
of the hydrocarbons produced from the Wells is subject to a sales contract or
other agreement relating to the production, gathering, transporting,
processing, treating or marketing of hydrocarbons except those which can be
terminated upon not more than three months notice.
7.15 Proceeds of Production. To Seller's best knowledge,
Buyer will be entitled to receive from all purchasers of production from the
Wells at least the NRI set forth in Exhibit B without suspense or any indemnity
other than the normal division order warranty of title, except where the
failure to receive same would not have a material adverse effect on the value
of the Assets.
7.16 Material Contracts. To Seller's best knowledge, and
subject to the execution of new contracts in the ordinary course of business if
a contract has expired or has been terminated, all contracts material to the
Assets are in full force and effect (the "Material Contracts"). No written
notices of material default have been received regarding the Material Contracts
that remain uncured, or that Seller has not made provisions for under the Amoco
Agreement so that such event of default will not have a material adverse effect
on the Assets.
7.17 Bills in the Ordinary Course. In the ordinary course
of business and to Seller's best knowledge, all costs and expenses pertaining
to the Assets have been timely paid, except where such payments are being
contested with good faith or except where the failure to make such payments
would not have a material adverse effect on the Assets.
7.18 Legal Proceedings. Except as set forth on Exhibit K,
no suit, action or other proceeding is pending against Seller or, to Seller's
best knowledge, threatened in writing before any court, governmental agency,
arbitrator or other panel that relates to the Assets or the transaction
contemplated by this Agreement that might (i) impair the parties ability to
consummate the transaction contemplated by this Agreement or (ii) cause the
impairment or loss
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of title to any material portion of the Assets or the value thereof, or (iii)
hinder or impede the operation or enjoyment of the Leases in any material
respect insofar as they relate to the Assets.
7.19 Compliance with Laws. To Seller's best knowledge,
subject to Seller's right to bring claims against Amoco following the Closing
Date based upon Seller's due diligence evaluations pursuant to Sections 4.2
(claims within 120 days following the Closing Date) and 5.2 (claims within 180
days following the Closing Date) of the Amoco Agreement, all laws, rules,
regulations, ordinances and orders (of all governmental and regulatory bodies
having authority over the Assets) material to the operation of the Assets have
been complied with in all material respects.
7.20 Environmental Matters. To Seller's best knowledge,
subject to Seller's right to bring claims against Amoco for a period of 180
days following the Closing Date based upon Seller's due diligence evaluations
pursuant to Section 5.2 of the Amoco Agreement, no conditions exist on the
Assets that would subject Buyer or any other party to any damages, remedial
action, injunctive relief or other liability under any Environmental Laws,
including without limitation, all costs associated directly or indirectly with
cleanup, removal, closure or other response actions; provided that Buyer or
such other party may be subject to such matters which are (i) routine in the
operation of the Assets and (ii) in the aggregate not material to the value of
the Assets as a whole. All material permits, licenses and approvals affecting
the Assets and required under Environmental Laws have been obtained and the
Assets are in material compliance with such permits, licenses and approvals.
As used herein, the term "Environmental Laws" shall have the
meaning set forth in the Amoco Agreement and further shall include any and all
existing laws (common or statutory), rules, regulations, codes, or ordinances
issued or promulgated by any federal, state or local governmental entity
relating to the management and disposal of waste materials, the protection of
public or employee health and safety, the cleanup, remediation or prevention of
pollution, or the protection of the environment.
7.21 Payment of Taxes. To Seller's best knowledge,
subject to Seller's right to bring claims against Amoco for a period of 120
days following the Closing Date based upon Seller's due diligence evaluations
pursuant to Section 4.2 of the Amoco Agreement, all ad valorem, property,
production, severance, excise and similar taxes and assessments based on or
measured by the ownership of property or the production of hydrocarbons or the
receipt of proceeds therefrom on the Assets which are currently due and payable
have been properly and timely paid, except to the extent such taxes are being
contested in good faith in the ordinary course of business.
7.22 Tax Partnerships. Except as set forth in Exhibit L,
no portion of the Assets (i) has been contributed to and is currently owned by
a tax partnership; (ii) is subject to any form of agreement (whether formal or
informal, written or oral) deemed by any state or federal tax statute, rule or
regulation to be or to have created a tax partnership; or (iii) otherwise
constitutes "partnership property" (as that term is used throughout Subchapter
K of Chapter 1 of Subtitle A of the IRC) of a tax partnership. Seller shall
retain all liability and responsibility, if any, to make all payments to
appropriate parties under the tax partnerships identified on Exhibit
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L. In addition to all other remedies available to Buyer, Seller shall
indemnify Buyer for all costs, losses, damages, penalties or expenses incurred
by Buyer as a result of any of the Assets having been contributed to or
currently owned by a tax partnership, and Buyer may elect, with a rebate in
accordance with the procedures of Section 12.3 and the provisions of Section
12.4, to reassign such Assets to Seller. For purposes of this Section 7.22, a
"tax partnership" is any entity, organization or group deemed to be a
partnership within the meaning of IRC Section 761 or any similar state or
federal statute, rule or regulation, and that is not excluded from the
application of the partnership provisions of IRC Subchapter K of Chapter 1 of
Subtitle A and of all similar provisions of state tax statutes or regulations
by reason of elections made, pursuant to IRC Section 761(a) and all such
similar state or federal statutes, rules and regulations, to be excluded from
the application of all such partnership provisions.
7.23 Other Tax Matters.
(a) NGPA Determination.
(i) Applications. Except for the
Wells listed on Exhibit M and subject to Seller's right to bring
claims against Amoco for a period of 120 days following the Closing
Date based upon Seller's due diligence evaluations pursuant to Section
4.3 of the Amoco Agreement, all necessary filings have been made with
the applicable state and federal agencies (the "Applications") for
well determination(s) for each Well under the Natural Gas Policy Act
of 1978, as amended (the "NGPA") and the rules and regulations of the
Federal Energy Regulatory Commission (the "FERC") under such act (the
"NGPA Regulations") requesting a determination that all or a
quantifiable portion of the gas produced from a particular Well is
"natural gas produced from designated tight formations" as defined in
18 C.F.R. Section 274.205(e). Each such application has been
approved by the indicated state and federal agency and by the FERC and
has been finally approved under and in accordance with Section 503 of
the NGPA. The Applications comply with the requirements of the NGPA
and the NGPA Regulations and do not (1) contain any untrue statement
of material fact or (2) omit any statement of material fact necessary
to make the statements therein not misleading. No further
applications are required under the NGPA and the NGPA Regulations to
allow the legal sale of all gas produced from the Wells at a price
equal to the price for such gas currently being received.
(ii) Other Wells. With respect to the
Wells listed on Exhibit M, Part I identifies Wells which have been
recompleted in accordance with private letter rulings issued by the
Internal Revenue Service ("IRS") to third parties, or which have been
or will be recompleted in an uphole formation in accordance with
Situation 1 of Revenue Ruling 93-54 into a "qualifying formation"
(tight formation or other qualifying formation) within the time frames
set forth in subsection (b) below, and Part II identifies Wells
drilled within the time frames set forth in subsection (b) below but
no certificate was obtained from either the state agency or the FERC
or both stating that the Well is qualified and Seller has a reasonable
basis to believe that such a certificate could have been obtained if
the state agency or the FERC were authorized to accept a
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request for such certificate. With respect to all the Wells listed on
Exhibit M, the hydrocarbons produced and sold from such Wells qualify
for the Tax Credit.
(iii) Wells Where Commingling With
Non-Qualified Production Is Conducted. For Wells, if any, where
production from a qualifying formation and production from a
non-qualifying formation are commingled, the production has been
allocated to each producing formation on a reasonable basis,
consistent with industry standards and in accordance with procedures,
if any, that have been approved by appropriate state and federal
agencies.
(b) Wells. Each Well (1) has been timely drilled
under IRC Section 29(f)(1)(A) (drilled after December 31, 1979 but before
January 1, 1993), or administrative interpretations thereof, and (2) has been
timely drilled under IRC Section 29(c)(2)(B)(ii) or administrative
interpretations thereof, or Seller has a reasonable basis to believe that the
well was committed to interstate commerce (as defined in Section 2(18) of the
Natural Gas Policy Act of 1978, as in effect on November 5, 1990) as of April
20, 1977.
(c) No Qualified Production prior to January 1,
1980. Prior to January 1, 1980, there was no production of oil or gas from,
nor were any wells drilled or completed on, the "property" (within the meaning
of IRC Section 29) on which any Well is located nor was any portion of any
such "property" included within a unit from which oil or gas was produced or in
which any wells were drilled or completed prior to such date.
(d) No Enhanced Oil Recovery Credit. No oil or
gas produced from the Wells qualifies or has qualified for (i) the enhanced oil
recovery credit or any other credit under IRC Section 43 and none has been
claimed or taken on such oil or gas, or (ii) the credit allowed under IRC
Section 38 by reason of the energy percentage with respect to property used in
the project.
(e) No Government Financing. No portion of any
drilling, equipping, seismic or other development costs of the Assets were
financed by any state, local or federal agency, directly or indirectly,
including by way of grant, loan, expenditure or loan guaranty.
(f) Seller Status. Seller is not a non-resident
alien, foreign corporation, foreign partnership, foreign trust or foreign
estate (as those terms are defined in the IRC and the rules and regulations
promulgated thereunder), and Seller shall deliver to Buyer affidavits of
non-foreign ownership in the forms set forth in Exhibit N.
8. Certain Tax Matters.
8.1 Opinion of Tax Counsel, Right to Request Ruling. At
Closing, Buyer at its sole cost, shall provide Seller a copy of the opinion
which Buyer has requested from Arthur Andersen LLP ("AA") regarding the tax
consequences of the transaction contemplated by this Agreement (the "Tax
Opinion"). Notwithstanding the Tax Opinion, Buyer shall have the right, but
not the obligation, to request a "private letter ruling" from the IRS to the
effect that (i) Buyer's interest in the Assets constitutes an economic interest
in minerals in place, and (ii) the Production Payment will be treated as a
mortgage loan under IRC Section 636 (a "Ruling"). Should
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Buyer elect to request a Ruling, Buyer shall have no right to terminate or
rescind this Agreement if the Ruling is not acceptable to Buyer. Seller shall,
in good faith, amend this Agreement and the documents contemplated hereunder in
order that Buyer may obtain a favorable Ruling, if, in Seller's sole and
reasonable discretion, such amendments will not have a material adverse effect
on Seller.
8.2 Tax Status. Seller and Buyer intend that, for tax
purposes only, the Production Payment will be treated as a carved out
production payment under IRC Section 636(a) and as a mortgage loan and not as
an "economic interest" in the Assets. Buyer shall have no recourse against
Seller in the event that the Production Payment is not so treated until the
commencement of a Tax Audit, in which event the provisions of Section 8.3 shall
control.
8.3 Escrow in the Event of Tax Audit. Promptly following
the earlier to occur of (1) the date which is 90 days following receipt by a
member of Buyer of a notice from the IRS of the commencement of an
administrative proceeding at the partnership level pursuant to IRC Section
6223(a)(1) (a "Tax Audit"), or (2) the date of issuance by the IRS of either
(i) a notice of proposed adjustment with respect to any audit proceedings or
(ii) a so- called "60 day letter" (such earlier date, the "Escrow Commencement
Date"), Seller and Buyer shall enter into an Escrow Agreement with an escrow
agent, substantially in the form of Exhibit U; provided, however, that Buyer
may waive its rights to enter into such an Escrow Agreement, in which event the
provisions of Sections 8.3(a) through 8.3(d) shall not apply. If Buyer does
not waive its rights to an Escrow Agreement, the Escrow Agreement and the funds
in the "Escrow Account" established pursuant thereto shall be administered in
accordance with the following provisions:
(a) All Credit Payment Amounts which become
payable after the Escrow Commencement Date, shall be deposited into
the Escrow Account. For tax purposes only, Buyer shall be treated as
the owner of the escrow funds.
(b) Buyer shall continue to deposit the Credit
Payment Amounts in the Escrow Account until the conclusion of a Tax
Audit. The escrow funds in the Escrow Account shall be released at
the conclusion of all ongoing Tax Audits. A Tax Audit will be deemed
to have concluded upon the earliest to occur of the following events:
(i) the receipt by Buyer of written notice from the IRS that it will
not assert any adjustments with respect to the transactions
contemplated by this Agreement; (ii) Buyer entering into a settlement
agreement with the IRS which resolves the open federal income tax
issues in connection with such transactions; (iii) a judgment of a
court of law or a decision in an administrative proceeding becoming
non- appealable with respect to the open federal income tax issues in
connection with such transactions; or (iv) the expiration of the
applicable period of limitations for making assessments with respect
to the years under examination in the Tax Audit if the IRS has made no
assessments within such period with respect to such transactions.
(c) Upon the event described in Section 8.3(b),
Buyer shall receive from the escrow funds in the Escrow Account an
amount, if any, equal to 70% of the total dollar amount of any
reduction in Post-Audit Tax Credits resulting from a Tax Audit, plus
interest on such amount at the rate applicable to the overpayment of
tax. For
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purposes of this Section 8.3(c), "Post-Audit Tax Credits" shall mean
the Tax Credits associated with Credit Payment Amounts with respect to
production and sales of Subject Hydrocarbons (as defined in the
Production Payment Assignment) after the commencement of the Tax Audit
and taking into account any reduction in tax credits resulting from
the Tax Audit in question, and the amount of any reduction in
Post-Audit Tax Credits resulting from a Tax Audit shall be determined
without regard to the effect of such reduction upon Buyer's actual
income tax liability. Interest described in the initial sentence of
this Section 8.3(c) shall run from the due date for Buyer's federal
income tax return for the year that the Post-Audit Tax Credits in
question were claimed.
(d) Upon the conclusion of all ongoing Tax Audits,
and the payment to Buyer of all amounts determined in accordance with
Section 8.3(c), Seller shall receive the remaining amount of the
escrow funds.
8.4 Settlements Resulting from a Tax Audit. If Buyer
elects to enter into a negotiated settlement with the IRS of any Tax Audit
adjustments, Buyer shall, in good faith, consult with Seller regarding the
suggested terms of such settlement; provided, however, that Buyer shall be
under no obligation to comply with any suggestion of Seller. Buyer shall
provide to Seller copies of all correspondence or pleadings between Buyer and
the IRS regarding any Tax Audit. Seller shall be entitled to monitor all
hearings and meetings with the IRS associated with such settlement
negotiations.
9. Covenants.
9.1 Cooperation and Access. Seller shall fully cooperate
with Buyer's post-Closing due diligence efforts, both at Seller's offices and
at the site of the Assets. Seller shall promptly deliver to Buyer copies of
all evaluations and correspondence regarding Seller's due diligence and title
and environmental defect claims asserted under the Amoco Agreement.
9.2 Insurance. At or prior to the Closing, Seller shall
cause Buyer to be named as an additional insured on all insurance policies
Seller has that pertain in any way to the ownership and operation of the
Assets. At Closing, Seller will provide Buyer with Certificates of Insurance
naming Buyer as an additional insured, or other evidence, satisfactory to
Buyer, of compliance with this Section 9.2.
10. Closing Conditions.
10.1 Seller's Closing Conditions. The obligation of
Seller to consummate the transactions contemplated hereby is subject, at the
option of Seller, to the satisfaction on or prior to the Closing Date of all of
the following conditions:
(a) Representations, Warranties and Covenants.
The (1) representations and warranties of Buyer contained in this
Agreement shall be true and correct in all respects on and as of the
Closing Date, and (2) covenants and agreements of Buyer to be
performed on or before the Closing Date in accordance with this
Agreement shall have been duly performed in all respects.
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(b) Closing Documents. Buyer shall have executed
and delivered the documents which are contemplated to be executed and
delivered by it pursuant to Section 11 hereof prior to or on the
Closing Date.
(c) No Action. On the Closing Date, no suit,
action or other proceeding (excluding any such matter initiated by
Seller or any of its affiliates) shall be pending or threatened before
any court or governmental agency or body of competent jurisdiction
seeking to enjoin or restrain the consummation of this Agreement or
recover damages from Seller resulting therefrom.
10.2 Buyer's Closing Conditions. The obligation of Buyer
to consummate the transactions contemplated hereby is subject, at the option of
Buyer, to the satisfaction on or prior to the Closing Date of all of the
following conditions:
(a) Representations, Warranties and Covenants.
The (1) representations and warranties of Seller contained in this
Agreement shall be true and correct in all respects on and as of the
Closing Date, and (2) covenants and agreements of Seller to be
performed on or before the Closing Date in accordance with this
Agreement shall have been duly performed in all respects.
(b) Closing Documents. Seller shall have
executed and delivered the documents which are contemplated to be
executed and delivered by it pursuant to Section 11 hereof prior to or
on the Closing Date.
(c) No Action. On the Closing Date, no suit,
action or other proceeding (excluding any such matter initiated by
Buyer or any of its affiliates) shall be pending or threatened before
any court or governmental agency or body of competent jurisdiction
seeking to enjoin or restrain the consummation of this Agreement or
recover damages from Buyer resulting therefrom.
(d) Tax Opinion. On or before the Closing Date,
Buyer shall have received the Tax Opinion described in Section 8.1.
11. Closing. The consummation of the transactions contemplated
hereby (the "Closing") shall occur, either in person or by facsimile, at the
offices of Davis, Graham & Stubbs LLP on the date of this Agreement (the
"Closing Date") or at such other time and place as the parties may agree to in
writing. At Closing, the following events shall occur, each being a condition
precedent to the others and each being deemed to have occurred simultaneously
with the others (except where the documents involved indicate otherwise):
11.1 Advance. Seller shall fund the Advance to Amoco on
behalf of Buyer.
11.2 Section 15.2 Payment. Seller and Buyer shall pay to
the other, in cash or its equivalent, the amount due pursuant to Section 15.2,
if any, as reimbursement for the expenses incurred in connection with this
transaction.
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11.3 Notice of Preferential Rights and Consents. Seller
shall deliver to Buyer a copy of the notices sent to and any responses received
from third parties regarding preferential rights to purchase and consents
affecting the Assets with respect to the transactions contemplated by this
Agreement.
11.4 Assignments; Recourse Note; Option. Seller and Buyer
shall execute and deliver the Wellbore Assignment, the Production Payment
Assignment, the Recourse Note and the Option. In addition, Seller shall
prepare and Seller and Buyer shall execute such other conveyances on official
forms and related documentation necessary to transfer the Assets to Buyer in
accordance with requirements of governmental regulations; provided, however,
that any such separate or additional conveyances required pursuant to this
Section 11.4 or pursuant to Section 15.1 (i) shall evidence the conveyance and
assignment of the Assets and interests therein made or intended to be made in
the Wellbore Assignment and the Production Payment Assignment, (ii) shall not
modify or be deemed to modify any of the terms, reservations, covenants and
conditions set forth in the Wellbore Assignment or the Production Payment
Assignment, and (iii) shall be deemed to contain all of the terms, reservations
and provisions of the Wellbore Assignment or Production Payment Assignment, as
appropriate, as though the same were set forth at length in such separate or
additional conveyance.
11.5 Non-Foreign Ownership Affidavits. Seller shall
deliver to Buyer the affidavits of non-foreign ownership substantially in the
forms set forth in Exhibit N, one stating that Seller is a non-foreign entity
for federal income tax purposes, and the other form stating that there is no
obligation for Colorado withholding tax under C.R.S. Section 39-22-604.5.
11.6 Evidence of Insurance. Seller shall provide Buyer
with certificates from Seller's insurers or other evidence that Buyer has been
named an additional insured on Seller's policies affecting the Assets.
11.7 Contribution Agreement. Buyer shall deliver to
Seller the Contribution Agreement by and among Fontenelle, Inc. and Bald
Prairie, Inc. as members of Buyer, Buyer and Seller (as a third party
beneficiary), substantially in the form set forth in Exhibit O.
11.8 Guaranty Agreement. Buyer shall deliver to Seller
the Guaranty Agreement from FMR Corp. in favor of Buyer as beneficiary and
Seller as third party beneficiary, substantially in the form set forth in
Exhibit O.
11.9 Seller's Officer's Certificate. Seller shall execute
and deliver to Buyer the Officer's Certificate, substantially in the form
attached as Exhibit P.
11.10 Opinion on Behalf of Seller. Seller shall deliver to
Buyer the opinion substantially in the form set forth in Exhibit Q.
11.11 Buyer's Manager's Certificate. Buyer shall execute and
deliver to Seller the Manager's Certificate substantially in the form attached
as Exhibit R.
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11.12 Opinion on Behalf of Buyer. Buyer shall deliver to
Seller the opinion of Davis, Graham & Stubbs LLP, substantially in the form set
forth in Exhibit S.
11.13 Management Agreement. Seller shall execute and
deliver to Buyer and Buyer shall execute and deliver to Seller the Management
Agreement (the "Management Agreement") and Memorandum of Management Agreement
and Power of Attorney substantially in the forms set forth in Exhibit T.
11.14 Performance Power of Attorney. Buyer shall execute
and deliver to Seller counterparts of a Limited Power of Attorney,
substantially in the form of Exhibit V.
11.15 Tax Opinion. Buyer shall deliver to Seller a copy of
the Tax Opinion of AA.
11.16 Additional Instruments. Seller and Buyer shall
execute, acknowledge and deliver to each other such additional instruments as
are reasonable and customary to accomplish the purposes of this Agreement.
12. Post-Closing Matters.
12.1 Files and Records. Following Closing, Seller shall
retain physical possession of all lease files, land files, division order
files, production marketing files and production records in Seller's possession
relating to the Assets (the "Records"). However, except to the extent that
Buyer's inspection thereof would violate legal constraints or legal
obligations, Buyer shall have the right to inspect the Records in Seller's
offices at any reasonable time. At Buyer's request in writing (which written
request may be delivered by facsimile), to the extent that Seller's delivery
thereof would not violate legal constraints or legal obligations, Seller shall
make copies of the Records or materials in the Records at Seller's expense and
shall deliver said copies to Buyer at Seller's expense, provided that Seller
may charge Buyer the actual costs for such copies and delivery if such costs
exceed $250 per request. If Buyer requires copies of the Records for its own
account, Seller will permit Buyer, at Buyer's own expense, to make copies of
pertinent material contained in the Records to the extent such action would not
violate legal constraints or legal obligations.
12.2 Sales Taxes and Recording Fees. Seller shall be
responsible for making the payment to the proper authorities of all taxes and
fees occasioned by the sale of the Assets, including without limitation, any
transfer fees and sales taxes (which are to be apportioned one-half to Seller
and one-half to Buyer), and any documentary, filing and recording fees required
in connection with the filing and recording of any assignments or conveyances
delivered hereunder in the appropriate county, federal and/or state records.
12.3 Rebates for Defective Interests. In addition to the
remedy provisions of Section 12.8, Buyer shall be entitled to the following
rebate if Seller does not have Defensible Title to the Assets. At any time and
from time to time during the due diligence periods under the Amoco Agreement,
if Buyer discovers that Seller breached the representation and warranty set
forth in Sections 7.8, 7.12 or 7.20, Buyer may give Seller a Notice of
Defective Interests, which
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notice shall describe the Defective Interest and the basis for the Defective
Interest. Buyer shall be entitled to a rebate for a Defective Interest in the
amount of $3,197,000 multiplied by a fraction, the numerator of which is the
volume of reserves (net to Buyer) allocated to the Wells affected by the
Defective Interest and the denominator of which is the total volume of reserves
(net to Buyer) allocated to all of the Wells in the Reserve Report; provided,
however, that if the Defective Interest does not remain in effect during the
entire productive life of the subject Well, such fact shall be taken into
account in determining the amount of such rebate.
The rebate calculated above shall be paid from Seller to Buyer
if and only if the aggregate amount to be rebated with respect to all Defective
Interests exceeds a threshold of $35,000, and if such amount is exceeded, the
rebate shall be made for all Defective Interests. In addition to any rebate on
account of Defective Interests, Buyer and Seller agree that all other express
dollar amounts, numbers or volumes set forth in this Agreement, the Production
Payment Assignment and Option, shall each be decreased, as appropriate, by
multiplying such amount or number, as the case may be, by a fraction, the
numerator of which is the aggregate volume of reserves associated with the
Assets without such Defective Interest and the denominator of which is the
total volume of reserves allocated to all of the Assets.
12.4 Rebates for Exercised Preferential Purchase Rights,
Failure to Obtain Consents. If the holder of any preferential purchase right
exercises such right and the affected Asset cannot validly be conveyed to
Buyer, or if a required consent (except for Governmental Consents) to assign is
not obtained or deemed obtained within 45 days following Closing and the
affected Asset cannot be validly conveyed to Buyer, a portion of the amount set
forth in Section 12.3 shall be rebated for the value of such affected Asset and
such affected Asset shall be excluded from the Assets conveyed to Buyer
pursuant to the terms hereof (collectively the "Excluded Assets"). The amount
of the rebate for an Excluded Asset shall be determined in accordance with the
provisions of Section 12.3. In addition to any rebate on account of Excluded
Assets, Buyer and Seller agree that all other express dollar amounts, numbers
or volumes set forth in this Agreement, the Production Payment Assignment and
Option, shall each be decreased, as appropriate, for the Excluded Assets in
accordance with the provisions of Section 12.3.
12.5 Reconveyance of Excluded Assets. Seller shall
provide to Buyer, within 60 days following Closing, copies of all responses
from third parties regarding the notices sent to such third parties pursuant to
Section 11.3. Upon written request from Seller, Buyer shall reconvey to
Seller, or Seller's designee, all Excluded Assets, free and clear of any
burdens, liens and encumbrances created by, through or under Buyer.
12.6 Allocation of Commingled Production and Costs.
Seller may have or acquire interests in the lands covered by the Leases that
are not part of the Assets ("Seller's Interests"), which are producing
hydrocarbons into a Well and such hydrocarbons are commingled with the
hydrocarbons produced from the Assets. Seller and Buyer shall use reasonable
efforts to ensure that hydrocarbon production from the Wells is allocated
between Seller's Interests and the Assets on a reasonable basis, consistent
with industry standards and in accordance with procedures, if any, that have
been approved by appropriate state and federal agencies. Costs and expenses
shall be allocated between the Seller's Interests and the Assets in
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accordance with the allocation of production between the Seller's Interests and
the Assets; provided that costs and expenses directly attributable to Seller's
Interests shall be allocated to such Seller's Interests, and costs and expenses
directly attributable to the Assets shall be allocated to and debited against
the Net Profits Account under the Production Payment Assignment.
12.7 Performance of Buyer. Seller shall be entitled to
the remedy of specific performance of Buyer's obligations under this Agreement
and the other documents contemplated hereunder in order to be assured of the
benefits contemplated under this Agreement, the Production Payment Assignment,
Option or Management Agreement. Should Buyer fail to perform any obligation
under this Agreement, the Production Payment Assignment, Option or Management
Agreement, which if unremedied would have a material adverse effect on Seller,
then Seller may give written notice to Buyer of such failure to perform. If
Seller gives such notice and Buyer does not remedy such failure within 60 days
of receipt of such notice, in addition to the remedy of specific performance,
Seller shall have the right to cause the attorney-in-fact of Buyer identified
in the Limited Power of Attorney to execute an Assignment, Bill of Sale and
Conveyance in a form substantially similar to that set forth in Exhibit V
covering any or all of the Assets which are adversely affected by such failure.
Seller and Buyer expressly waive any and all claims against the
attorney-in-fact named in the Limited Power of Attorney and any right to enjoin
such attorney-in-fact.
12.8 Overpayments. If at any time Buyer is determined to
have paid Seller more than the amount then due with respect to any Credit
Payment Amount, then as Buyer's exclusive remedy, Seller shall be obligated to
return any such overpayment, limited to amounts actually paid to Seller by
Buyer, after Buyer notifies Seller of the amount of such overpayment and
provides Seller substantiation thereof. Alternatively, without limiting
Buyer's recourse under the preceding sentence, Buyer may elect to offset the
amount of any such overpayment against future Credit Payment Amounts.
13. Apportionment of Liabilities and Obligations.
13.1 Buyer. Upon Closing, Buyer shall assume and pay for
all costs, expenses, liabilities and obligations accruing or relating to the
owning, operating or maintaining of the Assets or the producing, transporting
and marketing of hydrocarbons from the Assets, relating to periods on and after
the Effective Date, including without limitation, environmental obligations and
liabilities, off-site liabilities associated with the Assets, the obligation to
plug and abandon all Wells and reclaim all Well sites and all obligations
arising under agreements covering or relating to the Assets (collectively, the
"Post-Effective Date Liabilities").
13.2 Seller. Upon Closing, Seller shall retain, assume
and pay for all costs, expenses, liabilities and obligations accruing or
relating to the owning, operating or maintaining of the Assets or the
producing, transporting and marketing of hydrocarbons from the Assets, relating
to periods before the Effective Date, including without limitation,
environmental obligations and liabilities, the obligation to plug and abandon
wells (to the extent relating to periods prior to the Effective Date), off site
liabilities associated with the Assets, and all obligations arising under
agreements covering or relating to the Assets (collectively, the "Pre-Effective
Date Liabilities").
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<PAGE> 25
14. Indemnification. For the purposes of this Agreement, "Losses"
shall mean any actual loss, cost and expense (including reasonable fees and
expenses of attorneys, technical experts and expert witnesses), liability, and
damage (including those arising out of demands, suits, sanctions of every kind
and character); provided, however, that in no event shall "Losses" be deemed to
include consequential damages of a party to this Agreement.
14.1 Buyer's Indemnification of Seller. Subject to the
terms of and the indemnification obligations contained in the Management
Agreement, Buyer shall indemnify and hold harmless Seller, its officers,
directors, shareholders, employees, representatives, agents, successors and
assigns, forever, from and against all Losses and interest thereon which arise
from or in connection with (i) the Post-Effective Date Liabilities, and (ii)
Buyer's breach of its representations, warranties and covenants in this
Agreement.
14.2 Seller's Indemnification of Buyer. Subject to the
terms of and the indemnification obligations contained in the Management
Agreement, Seller shall indemnify and hold harmless Buyer; its officers;
directors; members; employees; representatives; agents; successors and assigns;
and the employees, representatives, agents, successors and assigns of such
members forever, from and against all Losses and interest thereon which arise
from or in connection with (i) the Pre-Effective Date Liabilities, and (ii)
Seller's breach of its representations, warranties and covenants in this
Agreement regardless of Seller's knowledge if such representations or
warranties are knowledge qualified, provided that the matters contemplated in
this clause (ii) shall not apply to the representations set forth in Section
7.6 or matters with respect to which this Agreement expressly provides an
exclusive remedy under Section 12.8. Buyer and Seller shall cooperate fully
and consult in good faith with each other in the litigation of any matter
identified in this Section 14.2.
Notwithstanding any of the foregoing provisions of this Section 14.2,
Buyer shall be entitled to payment for matters indemnified under this Section
14.2 only after a court of competent jurisdiction makes a final determination
regarding the matter litigated; provided that such payment shall cover only
Losses incurred by Buyer which have not been remedied by Seller under the
escrow provisions of Section 8.3 above and/or the overpayment provisions of
Section 12.8 above.
14.3 Third Party Claims. If a claim by a third party is
made against Seller or Buyer (an "Indemnified Party"), and if such party
intends to seek indemnity with respect thereto under this Section 14, such
Indemnified Party shall promptly notify Buyer or Seller, as the case may be
(the "Indemnitor"), of such claim. The Indemnitor shall have 30 days after
receipt of such notice to undertake, conduct and control, through counsel of
its own choosing and at its own expense, the settlement or defense thereof, and
the Indemnified Party shall cooperate with it in connection therewith; provided
that the Indemnitor shall permit the Indemnified Party to participate in such
settlement or defense through counsel chosen by such Indemnified Party,
however, the fees and expenses of such counsel shall be borne by such
Indemnified Party. So long as the Indemnitor, at its cost and expense, (1) has
undertaken the defense of, and assumed full responsibility for all Losses with
respect to, such claim, and (2) is reasonably contesting such claim in good
faith, by appropriate proceedings, the Indemnified Party shall not pay or
settle any
-20-
<PAGE> 26
such claim. Notwithstanding compliance by the Indemnitor with the preceding
sentence, the Indemnified Party shall have the right to pay or settle any such
claim, provided that in such event it shall waive any right to indemnity
therefor by the Indemnitor for such claim. If, within 30 days after the
receipt of the Indemnified Party's notice of a claim of indemnity hereunder,
the Indemnitor does not notify the Indemnified Party that it elects, at
Indemnitor's cost and expense, to undertake the defense thereof and assume full
responsibility for all Losses with respect thereto, or gives such notice and
thereafter fails to contest such claim in good faith, the Indemnified Party
shall have the right to contest, settle or compromise the claim but shall not
thereby waive any right to indemnity therefor pursuant to this Agreement.
15. Miscellaneous.
15.1 Further Assurances. After Closing, Seller and Buyer
shall execute, acknowledge and deliver or cause to be executed, acknowledged
and delivered such instruments and take such other action as may be reasonably
necessary or advisable to carry out the purposes and intents of this Agreement
and any document, certificate or other instrument delivered pursuant hereto.
15.2 Expenses. Seller and Buyer each agree to pay
one-half of the reasonable costs and expenses of Arthur Andersen LLP and Davis,
Graham & Stubbs LLP incurred in connection with this transaction, subject to
receipt of evidence and substantiation thereof. Such costs and expenses shall
not include any costs or expenses associated with the Tax Opinion. Seller and
Buyer shall pay their respective amount of taxes and fees, apportioned to each
under Section 12.2.
15.3 Notices. All notices under this Agreement shall be
in writing and addressed as set forth below. Any communication or delivery
hereunder shall be deemed to have been duly made and the receiving party
charged with notice (i) if personally delivered or telecopied, when received,
(ii) if mailed, three business days after mailing, certified mail, return
receipt requested, or (iii) if sent by overnight courier, one day after
sending. All notices shall be addressed as follows:
If to Seller:
HS Resources, Inc.
1999 Broadway, Suite 3600
Denver, Colorado 80202
Attn: General Counsel
Telephone: (303) 296-3600
Fax: (303) 296-3601
-21-
<PAGE> 27
If to Buyer:
WestTide Investments, LLC
c/o FMR Corp.
82 Devonshire Street, R22C
Boston, Massachusetts 02109
Attention: Roger D. Tullberg
Telephone: (617) 563-4791
Fax: (617) 476-6248
with a copy to:
Sullivan & Worcester
One Post Office Square
Boston, Massachusetts 02109
Attention: Christopher C. Curtis, Esq.
Telephone: (617) 338-2839
Fax: (617) 338-2880
Any party may, by written notice so delivered to the other party, change the
address or individual to which delivery shall thereafter be made.
15.4 Survival. The representations, warranties,
covenants, agreements and indemnities included or provided in this Agreement
shall survive the Closing. The doctrine of merger shall not cause any
representation, warranty, covenant, agreement or indemnity under this Agreement
to terminate as a result of Buyer and Seller entering into the Wellbore
Assignment, Production Payment Assignment, Option or any other instrument
contemplated hereunder.
15.5 Confidentiality. Buyer and Seller shall keep this
Agreement confidential except to the extent each may be required to disclose
the contents hereof by recording the Wellbore Assignment, Production Payment
Assignment, Option, and Memorandum of Management Agreement and Power of
Attorney in the real property records in the counties where the Assets are
located or filing the official forms of conveyances covering the Assets with
appropriate governmental authorities, the IRS or to the extent required in the
operation of the Assets, pursuant to the Management Agreement, by law,
regulation or order, in connection with obtaining third party consents and
waivers of preferential purchase rights and other matters, or in connection
with any public announcement issued in accordance with Section 15.6 hereof.
15.6 Announcements. Seller and Buyer shall consult with
each other regarding all press releases and other public announcements issued
at, prior to or following Closing concerning this Agreement or the transactions
contemplated hereby and except as may be required by applicable laws or the
applicable rules and regulations of any governmental agency or stock exchange.
Neither Buyer nor Seller shall issue any such press release or other public
announcement without the prior written consent of the other party, which
consent will not be unreasonably withheld. In all such press releases and
other public announcements, Seller shall refer to Buyer as being affiliated
with a large east coast financial institution.
-22-
<PAGE> 28
15.7 Assignment. Neither Buyer nor Seller may assign its
rights or delegate its duties or obligations under the terms of this Agreement
without the prior written consent of the other party, provided that either
Buyer or Seller may assign its rights, but not its obligations under this
Agreement, to any party (including any affiliated or nonaffiliated party) as
long as such assignment does not relieve the assigning party of its obligations
to the other party hereto, and provided further that Buyer may not cause or
permit an assignment, transfer, sale, alienation or other disposition of all or
any portion of the Assets which would result in the transferred Assets becoming
"plan assets" under the Employee Retirement Income Security Act of 1974, as
amended.
15.8 Binding Effect. This Agreement shall be binding upon
and shall inure to the benefit of the parties hereto and their successors and,
subject to Section 15.7 hereof, their assigns.
15.9 Complete Agreement. When executed by the authorized
representative of Seller and Buyer, this Agreement, the Exhibits hereto and the
documents to be delivered pursuant hereto shall constitute the complete
agreement between the parties. This Agreement may be amended only by a writing
signed by both parties.
15.10 Knowledge. As used in this Agreement, the term
"knowledge," "best knowledge" or any variations thereof shall mean the actual
knowledge of any fact, circumstance or condition by the officers or employees
at a manager or higher level of the party involved as such knowledge has been
obtained in the performance of their duties in the ordinary course of business
after making reasonable and appropriate inquiries.
15.11 Governing Law. THIS AGREEMENT SHALL BE GOVERNED BY
AND CONSTRUED IN ACCORDANCE WITH THE LAW OF THE STATE OF COLORADO WITHOUT
REFERENCE TO THE CONFLICT OF LAW PROVISIONS THEREOF.
15.12 Counterparts. This Agreement may be executed in one
or more counterparts, all of which shall be considered one and the same
agreement, and shall become effective when one or more counterparts have been
signed by each party and delivered to the other party.
-23-
<PAGE> 29
EXECUTED as of the date first above mentioned.
BUYER:
WESTTIDE INVESTMENTS, LLC
By: Its Manager, Fontenelle, Inc.
By:
----------------------------
Gary L. Greenstein
Vice President
SELLER:
HS RESOURCES, INC.
By:
----------------------------
George H. Solich
Vice President Acquisitions &
Divestitures
-24-
<PAGE> 30
STATE OF COLORADO )
CITY AND ) ss.
COUNTY OF DENVER )
The foregoing instrument was acknowledged before me this 11th day of
December, 1997, by George H. Solich, as Vice President Acquisitions &
Divestitures of HS Resources, Inc., a Delaware corporation, on behalf of such
corporation.
Witness my hand and official seal.
----------------------------
Notary Public
My commission expires:
------------
(SEAL)
STATE OF COLORADO )
CITY AND ) ss.
COUNTY OF DENVER )
The foregoing instrument was acknowledged before me this 15th day of
December, 1997 by Gary L. Greenstein, Vice President of Fontenelle, Inc., a
Delaware corporation, Manager of WestTide Investments, LLC, a Delaware limited
liability company on behalf of the company.
Witness my hand and official seal.
----------------------------
Notary Public
My commission expires:
-----------
(SEAL)
-25-
<PAGE> 1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our report included in this Form 10-K, into HS Resources, Inc.'s previously
filed Registration Statement File Nos. 333-46195, 333-21221, 33-61400 and
33-91934.
/s/ Arthur Andersen LLP
-----------------------
Arthur Andersen LLP
Denver, Colorado
March 31, 1998
<PAGE> 1
CONSENT OF INDEPENDENT ENGINEERS
Williamson Petroleum Consultants, Inc. (Williamson) hereby consents to (i)
the references to Williamson and our review entitled "Review of Oil and Gas
Reserves and Associated Net Revenues to the Interests of HS Resources, Inc. in
Certain Major-Value Properties in the Rocky Mountain and Gulf Coast Areas as
Prepared by HS Resources, Inc., Effective December 31, 1997, Constant Pricing
Economics, Williamson Project 7.8551" in the HS Resources, Inc. Annual Report on
Form 10-K filed with the Securities and Exchange Commission (the Commission) on
March 31, 1998, (ii) incorporation of the foregoing by reference in (a) the HS
Resources, Inc. Registration Statement Form S-3 initially filed with the
Commission on February 5, 1997, and any amendments thereof, and (b) the HS
Resources, Inc. Registration Statement Form S-3 initially filed with the
Commission on February 12, 1998 and (c) the HS Resources, Inc. Registration
Statements on Form S-8 initially filed with the Commission on April 21, 1993 and
May 5, 1995.
/s/ Williamson Petroleum Consultants, Inc.
------------------------------------------
Williamson Petroleum Consultants, Inc.
Houston, Texas
March 31, 1998
<PAGE> 1
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the reference of our firm in the HS Resources, Inc.
Annual Report on Form 10-K for the year ended December 31, 1997, filed with the
Securities and Exchange Commission (SEC) on March 31, 1998, and the
incorporation of the foregoing by reference in (a) the HS Resources, Inc.
Registration Statement Form S-3 initially filed with the SEC on February 5,
1997, and any amendments thereof; and (b) the HS Resources, Inc. Registration
Statement Form S-3 initially filed with the SEC on February 12, 1998 and (c) the
HS Resources, Inc. Registration Statements on Form S-8 initially filed with the
SEC on April 21, 1993, and May 5, 1995, and any amendments thereof.
/s/ Netherland, Sewell & Associates, Inc.
-----------------------------------------
Netherland, Sewell & Associates, Inc.
Dallas, Texas
March 31, 1998
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<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
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