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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
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[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
COMMISSION FILE NUMBER 0-18886
HS RESOURCES, INC.
(Exact name of Registrant as specified in its charter)
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<S> <C>
DELAWARE 94-3036864
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
ONE MARITIME PLAZA, FIFTEENTH FLOOR 94111
SAN FRANCISCO, CA (Zip Code)
(Address of principal executive offices)
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Registrant's telephone number, including area code: (415) 433-5795
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT
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TITLE OF EACH CLASS OF STOCK NAME OF EXCHANGE ON WHICH REGISTERED
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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 [ ]
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 29, 2000: $290,957,799.
Number of shares of Common Stock outstanding as of the close of business on
February 29, 2000: 18,796,552 after deducting 731,138 shares in treasury.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement of HS Resources, Inc. to be dated on or
before April 30, 2000, 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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PAGE
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Part I.
Item 1. Business.................................................... 3
Item 2. Properties.................................................. 8
Item 3. Legal Proceedings and Environmental Issues.................. 13
Item 4. Submission of Matters to a Vote of Security Holders......... 14
Part II.
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 15
Item 6. Selected Financial Data..................................... 16
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 17
Item 8. Financial Statements and Supplementary Data................. 39
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 65
Part III.
Items 10-13.............................................................. 65
Part IV.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 65
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PART I
ITEM 1. BUSINESS
THE COMPANY
HS Resources, Inc. ("HSR") is an independent energy company engaged in the
development, exploitation, exploration, production, acquisition, gathering,
transportation and marketing of oil and natural gas. We were organized as a
Delaware corporation in 1987. Our activities are all in the continental United
States, and all are onshore. Currently we have three primary operating
areas -- the Denver-Julesburg Basin in northeast Colorado (the "D-J Basin"), the
Gulf Coast area in south Louisiana and southeast Texas, and the northern Rocky
Mountain region. These operating areas are described more fully under Item 2.
"Properties -- Oil and Gas Properties." We conduct the majority of our oil and
gas activities ourselves.
Our principal subsidiaries are Resource Gathering Systems, Inc. and HS
Gathering, L.L.C., which hold our pipeline assets, and HS Energy Services, Inc.
("HSES"), our gas marketing, trading and transportation subsidiary. Our
principal executive offices are located at One Maritime Plaza, Fifteenth Floor,
San Francisco, California 94111 and our telephone number at that address is
(415) 433-5795.
During 1999 we produced 2.4 MMBbl of oil and 58.8 Bcf of natural gas, or
73.3 Bcfe (12.2 MMBoe). For the twelve months ended December 31, 1999, we
generated net cash flow of $92.5 million and net cash provided by operating
activities of $65.0 million. (Please see "Certain Definitions" for definitions
of abbreviations and other terms.) More detailed information about our operating
results is located in this report under Item 7. "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
At year-end 1999, we recorded proved reserves of 1.11 Tcfe of natural gas
(185.3 MMBoe), with estimated pre-tax present value (discounted at 10%) of $1.05
billion. Natural gas constituted approximately 78% of our reserves, and
approximately 66% of our reserves were classified as developed. At year-end we
owned interests in 4,044 wells, and we operated approximately 72% of them. More
detailed information about our reserves is located in this report under Item 2.
"Properties -- Oil and Gas Reserves," and more information about our properties
is located under Item 2. "Properties -- Oil and Gas Properties."
Effective December 31, 1998, we changed our method of accounting for our
oil and gas properties from the full cost method to the successful efforts
method. The financial information for all periods since inception of the Company
has been restated to reflect this method.
In addition, certain transactions in prior periods influence year-to-year
comparisons. In December 1997, we acquired from Amoco Production Company all of
Amoco's oil and gas properties in the D-J Basin. Effective September 1, 1998, we
sold our Mid-Continent oil and gas subsidiary, HSRTW, Inc. for $157.5 million in
cash and repaid a portion of our bank debt with the proceeds from our sale.
Then, in late 1999, we acquired from Kinder Morgan, Inc. ("KMI") certain natural
gas gathering and transmission assets. These transactions are described more
fully under "Recent Developments" below.
BUSINESS STRATEGY
Our objective is to build shareholder value by increasing our oil and gas
reserves and production. To achieve this objective, our strategy is to (i)
consolidate in our core areas, (ii) exploit our existing property base, (iii)
pursue focused exploration in prospective areas, and (iv) apply advanced
technologies in all areas of our business.
Consolidation. We have been active in the D-J Basin since 1982, and since
that time we have drilled more than 1,300 wells. Throughout that time, we have
conducted many engineering, geologic and operational studies in the area, and
have accumulated a large database of information and knowledge about the
hydrocarbon potential and production characteristics there. This knowledge and
experience, combined with our established infrastructure, led us to conclude
that the area would benefit from
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consolidation, both to tap its full potential and to maximize operating
efficiencies. Thus, in 1996 we acquired the D-J Basin assets of Basin
Exploration, Inc. and Freedom Energy, Inc. In 1997 we acquired Amoco Production
Company's D-J Basin properties. In December 1999, we acquired KMI's gas
gathering and transmission assets and an ownership interest in the BP Amoco
Wattenberg Gas Processing Plant. (This latter transaction is described more
fully under "Recent Developments.") We currently operate almost 3,000 wells in
the D-J Basin, nearly 1,800 of which are connected to our gathering system. More
importantly, our consolidation activities have given us a substantial inventory
of projects with reduced operational risk but with attractive rates of return.
Exploitation. We have several thousand low risk exploitation projects in
our inventory, including such activities as drilling infill and other
development locations, deepening existing wells to new formations, recompleting
new formations in existing wells, and re-stimulating currently producing zones.
Recent results of our exploitation program are set forth under Item 2.
"Properties -- Oil and Gas Properties."
Exploration. Our approach to exploration is to focus on plays and projects,
rather than individual prospects, where we can use advanced technologies and
employ in-house knowledge and expertise to gain a competitive advantage.
Currently we have 21 major projects located in the onshore Gulf Coast region,
where we have acquired more than 900 square miles of 3-D seismic data. In
addition, we are currently working four project areas in the Mid-Continent
(Oklahoma) and we have a large acreage position in the Northern Rockies. Recent
results of our exploration efforts are set forth under Item 2.
"Properties -- Oil and Gas Properties."
Technology. Our most visible technology is the application of 3-D seismic
in our exploration programs. Use of this technology typically reduces
exploratory drilling risk and enhances economic results. Our 3-D seismic
inventory includes more than 1,500 square miles of data that have been acquired
and are in various stages of interpretation. Other technologies applied by us
include reservoir simulators, directional drilling techniques and fully
integrated digital databases, each of which aids in the efficient development of
oil and gas. In addition, we utilize proprietary systems 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.
MARKETING
Gas Marketing. Approximately 25% of our natural gas is subject to a
buy/sell arrangement with Duke Energy Field Services that effectively allows us
to sell this gas to our marketing subsidiary, HSES at market rates with Duke
profiting from a share of the extracted natural gas liquids. Approximately an
additional 70% of our gas is sold by HS Resources, Inc. directly to HSES at
market rates. HSES then sells the gas to a variety of customers including end
users, local distribution companies, pipelines and other marketers. Most
contracts are for a short term and provide for market indexed pricing. The
natural gas market provides us with numerous potential customers. Thus, we are
not dependent on any one customer for the ultimate sale of our gas.
Oil Marketing. Approximately 50% of our current oil production is subject
to a "call" by BP Amoco. In other words, BP Amoco has the right, which it has
historically always exercised, to purchase the oil at market rates.
Approximately 35% of our current oil production is sold to Conoco, and the rest
is sold to other purchasers, all at market rates under contracts for one year or
less. The market for crude oil, like that for gas, contains numerous potential
customers so that the loss of any one customer would not have an adverse effect
on us.
Trading and Hedging. The gas trading activities of HSES, and our oil and
gas hedging program are described under Item 7. "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
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RECENT DEVELOPMENTS
On November 26, 1999 we acquired the Wattenberg gas gathering and
transmission assets ("Wattenberg Gathering System") from KMI for an adjusted
purchase price of approximately $48 million plus the future assumption of an
operating lease which had a present value of $19 million. Although the formal
closing of the transaction is scheduled to occur in December of 2001, we have
assumed operational control of the system and bear the risks and receive the
benefits of ownership.
The Wattenberg Gathering System consists of a low pressure gathering system
and a high pressure transmission system. The low pressure gathering system
consists of more than 1,500 miles of pipeline and 3,000 horsepower of
compression, located in five northeastern Colorado counties. The low pressure
system delivers the gas to the inlet of the high pressure transmission system,
which consists of almost 60 miles of high pressure pipeline and almost 40,000
horsepower of compression.
Nearly 1,800 of our wells are connected to the Wattenberg Gathering System,
and our operated production represents more than 65% of the total system daily
throughput of approximately 200 million cubic feet of natural gas per day as of
year-end 1999. Along with the system, we acquired a 6.9% interest in the BP
Amoco Wattenberg Gas Processing Plant, and a right of first refusal to purchase
the remaining 93.1% interest in the plant. The acquisition is being accounted
for using the purchase method of accounting.
INTERNAL REVENUE CODE SECTION 29 TAX CREDITS
Internal Revenue Code Section 29 provides tax credits for natural gas
produced from certain types of reservoirs. The credit is available through the
end of 2002. Some, but not all, of our gas production qualifies for this tax
credit. However, because much of our net income typically has been sheltered,
for tax purposes, by such things as intangible drilling and development costs,
these tax credits would have been lost and could not have been carried forward.
As a result, we and our professional advisors structured certain transactions
through which we have retained a significant portion of the value of the Section
29 tax credits that would otherwise have been lost to us because of our tax
position. In each transaction, we convey substantially all of the working
interest in credit-qualified properties to a limited liability company owned by
one or more large financial institutions. We retain both an option to reacquire
the properties and a 100% production payment in the properties until 95% of the
net present value of the properties is produced. The effect of the transactions
is that we receive the production-related cash flow that we would have received
if we were the working interest owner, and the investor receives tax credits.
The investor makes an initial payment to us, and makes periodic payments that
vary depending on the volume of credit-qualified gas produced. The transactions
are structured in accordance with private letter rulings issued by the Internal
Revenue Service to third parties. In some cases, the investors obtain private
letter rulings that specifically cover our transactions. Through these
transactions, we have recognized approximately $10.1 million and $8.6 million of
"other gas revenues" associated with the tax credits during the years ended
December 31, 1999 and 1998, respectively. We expect to receive approximately $23
million for tax credits for the period 2000 through 2002, based on current
production estimates. See Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
COMPETITION
The oil and gas industry is highly competitive. We compete with major oil
companies, other independent oil and gas concerns and individual producers and
operators for opportunities and talented personnel. Many of these competitors
have substantially greater financial and other resources than HSR.
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REGULATION
The following discussion of regulation of the oil and gas industry is
necessarily brief and is not intended to constitute a complete discussion of the
various statutes, rules, regulations or governmental orders to which our
operations may be subject.
Price Controls on Liquid Hydrocarbons. There are currently no federal price
controls on oil production. There can be no assurance, however, that Congress
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 under the Natural Gas Act, the Natural Gas Policy Act, and the
regulations issued under the Act by the Federal Energy Regulatory Commission
("FERC"). Maximum selling prices of certain categories of gas sold in "first
sales" were regulated pursuant to the Natural Gas Policy Act. On July 26, 1989,
the Natural Gas Wellhead Decontrol Act was enacted removing, as of January 1,
1993, all remaining federal price controls from gas sold in "first sales." FERC
retains its jurisdiction over gas transportation.
Beginning in the mid-1980s and continuing until the present, FERC
promulgated a series of orders designed to correct perceived market distortions
and to make gas markets more competitive by, among other things, removing the
transportation barriers to market access. These orders have had a significant
impact upon gas markets in the United States and have fostered the development
of a large spot market for gas and increased competition for gas markets. As a
result of FERC orders, producers can access gas markets directly but face
increased competition for those markets and must operate under complex
transportation tariffs in order to take advantage of the opportunity to directly
market their gas.
Interstate pipelines continue to be regulated by FERC under the Natural Gas
Act. The high pressure transmission line that HSR has acquired from KMI is
currently subject to FERC jurisdiction. FERC regulations require extensive
reporting, advance approval of system changes or expansion, and control of
tariff and rate provisions. While KMI will handle regulatory compliance until
closing of the transaction expected in December, 2001, we will have significant
reporting obligations to KMI during that period and will be subject to the
construction, operation, tariff and rate constraints imposed by FERC.
Various state commissions also regulate the rates and services of pipelines
whose operations are purely intrastate in nature. Some state utility
commissions, including the Colorado Public Utilities Commission, now require
that intrastate pipeline and local distribution public utilities offer open
access, non-discriminatory transportation which allows consumers connected to
those systems to contract with producers or other suppliers for gas.
State and Local Regulation of Drilling and Production. State regulatory
authorities have established rules and regulations governing, among other
things, permits for drilling and production, drilling and operations,
performance bonds, reports concerning operations, discharge, disposal and other
waste-related permits, well spacing, unitization and pooling of operations,
taxation, environmental and conservation matters. A few states (Texas and
Louisiana, for example) also limit production from wells but this currently has
no effect on our wells. Some states have also enacted statutes establishing
maximum rates of production from oil and gas wells.
Environmental Regulations. Our operations are subject to complex and
constantly changing environmental laws and regulations adopted by federal, state
and local governmental authorities. Also, the discharge of oil, gas or other
pollutants into the air, soil or water may give rise to significant liabilities
of HSR to the government and/or third parties. Moreover, we have agreed to
indemnify certain sellers of producing properties from whom we have acquired
properties against certain liabilities for environmental claims associated with
the properties purchased by us. Compliance with environmental laws has not had a
material adverse effect upon us to date and we are not aware of any matter that
is likely to have a material adverse effect on us in the future. No assurance
can be given, however, that existing environmental laws or regulations, as
currently interpreted or as may be interpreted in the future, or future laws,
regulations and policies will not materially adversely affect our results of
operations and financial condition or that material indemnity claims will not
arise against us with respect to properties we acquire. For a discussion of
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particular environmental issues currently affecting the Company, see Item 3.
"Legal Proceedings and Environmental Issues," and Note 11 to Consolidated
Financial Statements.
Federal Leases. Operations on federal leases must be conducted in
accordance with permits and regulations issued by the Bureau of Land Management
or other federal agencies and are subject to a number of other regulatory
restrictions. In addition, on certain federal leases prior approval of drillsite
operations must be obtained from the Environmental Protection Agency ("EPA").
Although we hold interests in many federal oil and gas leases, very few of our
producing operations are located on these leases.
TITLE TO PROPERTIES
We generally obtain a title opinion prior to beginning drilling operations
on properties. We have obtained title opinions on substantially all of our
producing properties and believe that we have satisfactory title to such
properties in accordance with standards generally accepted in the oil and gas
industry. Customary royalty interests, liens for current taxes and other matters
generally burden our properties. These burdens do not materially interfere with
the use or affect the value of such properties. We have mortgaged a portion of
our properties to secure borrowings under our credit facilities. Consistent with
standard industry practice, our title investigation before acquiring undeveloped
properties is typically less rigorous than that conducted prior to drilling a
well.
OPERATIONAL HAZARDS AND INSURANCE
Our operations are subject to the usual hazards incident to the drilling
and production of oil and gas, as well as the gathering and transportation of
gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas
or well fluids, fires, pollution, releases of toxic gas and other environmental
hazards and risks. These hazards can cause personal injury and loss of life,
severe damage to and destruction of property and equipment, pollution or
environmental damage and suspension of operations.
We have engaged Insurance Management Associates, Inc., one of the world's
largest insurance brokerage firms, to procure various types of coverage for our
operations. We believe our insurance coverage is reasonable and prudent for the
types of risks we expect to encounter. Our insurance does not cover every
potential risk associated with the drilling, production, storage and
transportation of oil and gas and, while certain environmental coverage is
provided, coverage is not obtainable for all types of environmental hazards. The
occurrence of a significant adverse event, the risks of which are not fully
covered by insurance, could have a material adverse effect on our financial
condition and results of operations. Moreover, we cannot assure you that we will
be able to maintain adequate insurance in the future at rates we consider to be
reasonable.
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OFFICES
In addition to our San Francisco location we have offices in several cities
in Colorado, two offices in Oklahoma and one in Texas. At December 31, 1999, we
had 316 employees, with 27 located in San Francisco, California, 98 in Denver,
Colorado, 136 in Evans, Colorado, 37 in Brighton, Colorado, 11 in Tulsa,
Oklahoma, 3 in Oklahoma City, Oklahoma and 4 in Houston, Texas. None of our
employees is subject to a collective bargaining agreement. We consider our
relations with our employees to be good.
HSR leases the following office space:
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SQUARE MONTHLY LEASE
LOCATION FOOTAGE RENTAL EXPIRATION
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San Francisco, CA............................. 20,548 $ 41,096 December, 2003
Denver, CO.................................... 52,749 66,302 June, 2003
Evans, CO..................................... 17,985 9,600 February, 2009
Tulsa, OK..................................... 6,766 7,981 March, 2002
Houston, TX................................... 5,362 4,692 April, 2000
Oklahoma City, OK............................. 2,248 1,557 Month-to-Month
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105,658 $131,228
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In addition, pursuant to the KMI transaction HSR has acquired and is
occupying 26,798 square feet of office space in Brighton, Colorado. See "Recent
Developments."
ITEM 2. PROPERTIES
OIL AND GAS PROPERTIES
The following tables summarize certain information with respect to each of
our areas of operations and production. All information is presented as of
December 31, 1999.
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PROVED RESERVES
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GAS OIL PERCENT OF
OIL GAS EQUIVALENT EQUIVALENT TOTAL
(MBBL) (MMCF) (MMCFE) (MBOE) RESERVES
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D-J Basin................................. 38,851 837,598 1,070,705 178,451 96.3
Gulf Coast................................ 1,773 29,397 40,038 6,673 3.6
Northern Rockies and other................ 4 786 807 134 0.1
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Total........................... 40,628 867,781 1,111,550 185,258 100.0
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OTHER INFORMATION
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NET NET GROSS 3-D SEISMIC
TOTAL GROSS PERCENT PRODUCTION PRODUCTION UNDEVELOPED DATA
WELLS(1) OPERATED (MCFE/DAY)(2) (BOE/DAY)(2) ACREAGE(3) (SQUARE MILES)
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D-J Basin................ 3,993 72 184,513 30,752 202,192 124
Gulf Coast............... 44 48 22,048 3,675 213,912 927
Northern Rockies and
other.................. 7 29 566 94 246,045 451
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Total.......... 4,044 72 207,127 34,521 662,149 1,502
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(1) Includes 931 D-J Basin wells in which we own only overriding royalty
interests.
(2) Calculated for the quarter ended December 31, 1999.
(3) Includes leasehold, option and seismic rights.
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Denver-Julesburg Basin. The D-J Basin, located in northeastern Colorado,
has been our primary producing region for almost 20 years. One of the attractive
features of D-J Basin geology is its potential for multiple pay zones in a
single wellbore. In a section only 3,500 feet thick, there are at least seven
potentially productive formations. Three of the formations, the Codell, Niobrara
and J-Sand, are "blanket" zones in our Wattenberg Field area, located
approximately 35 miles north and east of Denver. The Codell and Niobrara
formations are found there at depths ranging from 6,400 to 7,700 feet and the
J-Sand is found between 7,400 and 7,800 feet. Codell and Niobrara wells produce
oil and natural gas, while J-Sand wells produce primarily gas. Our D-J Basin
production and reserves are largely found in these formations. Although more
localized in extent, we also have production from the deeper D-Sand and Dakota
sandstones and the shallower Sussex and Shannon sandstones. Drilling success
rates have historically been high, and production from these formations is
characterized by strong initial production flows and long-lived reserves.
Production also tends to be a combination of oil and gas. Gas produced in the
central part of the D-J Basin, including the Wattenberg Field area, has an
energy content ranging from 1,150 to 1,350 Btu per cubic foot, which typically
enhances wellhead value.
We have a large inventory of projects in the D-J Basin comprised of
development drilling in existing spacing units, recompletions of currently
nonproducing formations in existing wells, restimulating ("refracing") currently
producing formations, and deepening existing wells to new formations. We also
have several exploration leads in this area.
During 1999 we conducted 397 activities in the D-J Basin. Key activities
included refracing the Codell formation in 272 wells, drilling 28 new J-Sand
wells, deepening 52 other wells to the J-Sand, recompleting uphole formations in
23 wells, and 22 Dakota formation tests.
Greater D-J Basin. The Greater D-J Basin is located generally south and
east of the Wattenberg field. Production in the Greater D-J Basin is generally
found in D-Sand and J-Sand channels. Within the D-Sand and J-Sand, high
porosities and permeabilities can yield higher flow rates of oil and/or natural
gas than those found in Wattenberg wells. 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.
Gulf Coast Region. We also have established a core geographic focus in
onshore south Louisiana and the upper Texas Gulf Coast. Our activities there
target both shallow exploitation and deeper exploration projects. Our typical
approach is to augment our geologic interpretation by applying geophysical
expertise to normal and slightly over-pressured formations. Our primary areas of
interest include Acadia, Allen, Jefferson Davis, Beauregard, Calcasieu, St.
Landry and Evangaline Parishes of Louisiana and Chambers, Jefferson, Ft. Bend
and Matagorda Counties in Texas. The complex faulted and prolific salt dome
dominated region possesses numerous reservoir targets that, in various
combinations, provide attractive multi-zone drilling prospects. Wells in the
area target the Frio, Hackberry, Vicksburg, Yegua, Sparta and Wilcox formations
at depths ranging from 3,000 to 13,500 feet with most targets between 8,000 and
12,000 feet.
To date, we have acquired more than 900 square miles of advanced 3-D
seismic data to support an exploration and exploitation effort on 21 major
project areas. During 1999, our Gulf Coast program continued the drilling phase
on several projects as we participated in 26 gross wells, of which 15 were
successful.
During 1999, we continued to exploit our technical knowledge of the rotated
Hackberry play. In particular, we began developing the Indian Village project
area, directly east of our North Gillis project, where we drilled six successful
wells in six attempts. HSR operates the project and owns a 50% working interest.
We drilled one additional Hackberry discovery in the North Gillis project area
which we operate (37.5% working interest). Activity on the HSR-operated Edgerly
project included drilling two wells. One was a successful Hackberry completion
(6.25% working interest) and the other was plugged and abandoned after finding
the reservoir previously depleted by a downdip well (25% working interest). The
Roanoke project (50% working interest) had additional activity, resulting in one
successful Hackberry well. Two additional successful wells were drilled in the
Buhler project area where we have participated as a small interest non-operating
partner.
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In Texas, we drilled three exploratory wells on the Big Creek project
targeting the deeper Vicksburg and Yegua horizons, one of which was successful.
We also drilled one shallow dry hole targeting the Frio. At Caney Creek (25%
working interest), we participated in four wells, one of which was successful.
At Devillier, we drilled two additional wells, one where we had a carried
working interest. Both wells were dry holes. In the Lox B project area, we
drilled one Vicksburg discovery (50% working interest) and participated in an
unsuccessful second Vicksburg test (37.5% working interest).
Also during 1999, we acquired seismic data on two additional rotated
Hackberry project areas, Hathaway and Starks, both in Louisiana.
Northern Rockies. We currently have four active areas in the Green River
Basin: South Jonah, North Pinedale, Gold Coast, and Adaville (coal bed methane).
In 1999, we drilled in South Jonah, North Pinedale and Gold Coast. Our five 1999
wells have established a large potential gas resources base, but we are
uncertain whether the resource can be produced economically. We are selling gas
in both North Pinedale and South Jonah. At Gold Coast, we tested significant gas
from both the Almond and Blair formations. Work is underway to determine the
economic viability of development in these areas. For example, in North Pinedale
we are integrating our D-J Basin completion expertise with our 3-D seismic
database and expertise, evaluating additional potential pay zones in the Steele
#16-31 wellbore, and evaluating offset potential to the Sherlock Federal #15-8.
In South Jonah we are testing different drilling and completion techniques.
ACREAGE
The following table sets forth the gross and net developed and undeveloped
acres on which we own the rights to conduct exploration and development activity
as of December 31, 1999.
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DEVELOPED ACRES UNDEVELOPED ACRES(1)
----------------- ---------------------
AREA GROSS NET GROSS NET
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D-J Basin............................................. 541,718 429,344 202,192 184,038
Gulf Coast............................................ 8,399 2,474 213,912 76,247
Northern Rockies...................................... 2,627 922 226,072 159,576
Mid-Continent......................................... -- -- 19,973 11,649
------- ------- ------- -------
Total....................................... 552,744 432,740 662,149 431,510
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</TABLE>
- - ---------------
(1) Includes acres upon which we own options to lease and seismic permits as
well as oil and gas leases.
OIL AND GAS RESERVES
Since 1998, Netherland, Sewell & Associates, Inc. ("NSA") has reviewed our
estimates of proved reserves, projected future production and estimated future
net revenues from production of proved reserves. For several prior years NSA
reviewed only Mid-Continent reserves and a different independent consulting firm
reviewed our other reserve estimates. We elected in 1998 to use NSA as our sole
outside reserve consultant because of its familiarity with the D-J Basin
generally and more specifically with the Amoco properties that we purchased in
late 1997. NSA also was equipped to handle electronically our large base of
data. NSA's estimates were based upon a review of production histories and other
geologic, economic, ownership and engineering data provided by or available to
us. In the aggregate, NSA reviewed proved properties constituting 80% of our
pre-tax present value of total proved reserves.
In determining the estimates of the reserve quantities that are
economically recoverable, we used selling prices (without consideration of
hedging effects) and estimated development and production costs which were in
effect as of December 31, 1999. 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,
1999, derived from our reserve reports. The present value
10
<PAGE> 11
(discounted at 10%) of estimated future net revenues before income taxes shown
in the table is not intended to represent the current market value of the
estimated oil and gas reserves owned by HSR.
<TABLE>
<CAPTION>
NET PROVED RESERVES
AS OF DECEMBER 31, 1999
------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ----------
<S> <C> <C> <C>
Oil and condensate (MBbl)................................ 24,268 16,360 40,628
Gas (MMcf)............................................... 585,465 282,316 867,781
Equivalent gas (MMcfe)................................... 731,075 380,475 1,111,550
Equivalent barrels (MBoe)................................ 121,846 63,412 185,258
Present value of estimated future net revenues before
income taxes (discounted at 10%) (in thousands)........ $857,166 $193,898 $1,051,064
</TABLE>
There are many uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond our control. The reserve data
presented above represent only estimates. Reserve engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
measured in an exact way, and the accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates made by different engineers
often vary from one another. In addition, results of drilling, testing and
production subsequent to the date of any estimate may justify revision of the
estimate, either upward or downward, and such revision may be material.
Accordingly, reserve estimates often differ from the quantities of oil and gas
ultimately recovered. Furthermore, the estimated future net revenues from proved
reserves and the present value of those reserves are based upon certain
assumptions, including prices, future production levels and cost, that may not
prove correct over time.
Predictions about prices and future production levels are very uncertain.
This is particularly true as to proved undeveloped reserves, which are by their
nature less certain than proved developed reserves, and which comprise a
significant portion of our proved reserves. Pricing assumptions materially
affect the calculation of present value of future net revenues, principally in
two ways. First, higher or lower prices directly affect estimated cash flows
attributable to a given reserve and production stream. Second, higher or lower
prices also increase or decrease the number of potentially recoverable barrels
of oil or cubic feet of gas. This is because wells reach their economic limit
earlier in a lower product price environment than in a higher price environment,
hence truncating the economic recovery of reserves.
Oil and gas prices have fluctuated widely in recent years. The weighted
average sales prices utilized for the purposes of estimating our proved reserves
and future net revenue therefrom at December 31, 1999, were $23.55 per Bbl of
oil and $2.49 per Mcf of gas. For cautions regarding forward-looking statements
made or implied by us see Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Disclosure Regarding
Forward-Looking Statements" and "Certain Considerations."
For further information concerning the present value of future net revenue
from HSR's proved reserves, see Note 15 of the Notes to Consolidated Financial
Statements.
Since December 31, 1990, as an operator of domestic oil and gas properties,
HSR has filed Department of Energy Form EIA-23, "Annual Survey of Oil and Gas
Reserves," as required by Public Law 93-275. There are differences between the
reserves as reported on Form EIA-23 and as reported 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 than on a net interest basis), while reserves reported herein are net to
HSR.
11
<PAGE> 12
DRILLING ACTIVITY
The following table sets forth the net wells we drilled and completed
during the periods indicated. Substantially all of our wells produce both oil
and gas. This table excludes deepenings, refracs and recompletions in existing
wells, which constituted a large portion of our 1999 activities.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1999 1998 1997
----- ----- -----
<S> <C> <C> <C>
Development:
Productive................................................ 22.9 59.4 65.3
Non-productive............................................ 0.0 0.0 5.3
---- ---- ----
Total............................................. 22.9 59.4 70.6
---- ---- ----
Exploratory:
Productive................................................ 6.0 7.3 14.2
Non-productive............................................ 7.0 7.1 9.7
---- ---- ----
Total............................................. 13.0 14.4 23.9
---- ---- ----
Total wells................................................. 35.9 73.8 94.5
==== ==== ====
</TABLE>
PRODUCTIVE OIL AND GAS WELLS
As of December 31, 1999, we owned interests in the following productive oil
and gas wells:
<TABLE>
<CAPTION>
GROSS PRODUCTIVE WELLS(1) NET PRODUCTIVE WELLS(1)
--------------------------- -----------------------------
NON- NON-
OPERATED OPERATED TOTAL OPERATED OPERATED TOTAL
-------- -------- ----- -------- -------- -------
<S> <C> <C> <C> <C> <C> <C>
Oil.................................. 1,793 174 1,967 1,754.9 38.3 1,793.2
Gas.................................. 1,108 38 1,146 1,006.9 10.0 1,016.9
----- --- ----- ------- ---- -------
Total...................... 2,901 212 3,113 2,761.8 48.3 2,810.1
===== === ===== ======= ==== =======
</TABLE>
- - ---------------
(1) We also have overriding royalty interests in 931 gross (50.0 net) wells that
are not reflected in these numbers.
Wells are classified as oil or gas producers as described in statutory
definitions based on oil/gas ratios. As a result, most of our wells are
categorized as oil wells, even though, on an equivalent Btu basis, such wells
tend to produce more gas than oil.
Our well count, compared to that reported at December 31, 1998, is affected
by our sale of properties to Southwestern Eagle and our property trade with
Patina. The net effect of these two transactions was to reduce the number of
gross wells which we own, increase our interests in wells which we retained, and
increase the number of wells that we operate.
12
<PAGE> 13
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table provides certain information regarding the costs we
have incurred in our development, exploration and acquisition activities during
the periods indicated (in thousands).
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1999 1998 1997
------- -------- --------
<S> <C> <C> <C>
Acquisition costs:
Unproved properties....................................... $12,908 $ 15,414 $130,169
Proved properties......................................... 201 12,615 226,458
Exploration costs........................................... 6,490 10,747 12,856
Development costs........................................... 67,760 78,736 44,375
------- -------- --------
Total costs incurred.............................. $87,359 $117,512 $413,858
======= ======== ========
</TABLE>
PRODUCTION
The following table sets forth our oil and gas production data during the
periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Net production:
Oil and condensate (MBbl)................................ 2,410 2,630 2,400
Gas (MMcf)............................................... 58,799 56,969 41,125
Equivalent gas (MMcfe)................................... 73,257 72,750 55,524
Equivalent barrels (MBoe)................................ 12,210 12,125 9,254
Average net daily production(1):
Oil and condensate (Bbl)................................. 6,959 6,378 6,679
Gas (Mcf)................................................ 165,371 141,336 117,589
Equivalent gas (Mcfe).................................... 207,127 179,604 157,663
Equivalent barrels (Boe)................................. 34,521 29,934 26,277
Average sales price per unit:
Oil and condensate ($/Bbl)............................... $ 15.70 $ 14.58 $ 19.71
Gas ($/Mcf).............................................. $ 2.16 $ 1.96 $ 2.19
Lease operating expense ($/Mcfe)........................... $ 0.38 $ 0.42 $ 0.45
Lease operating expense ($/Boe)............................ $ 2.29 $ 2.51 $ 2.69
</TABLE>
- - ---------------
(1) Average daily production for 1999, and 1998 and 1997 was calculated for the
quarter ended December 31, because we believe that to be a more indicative
presentation of current performance.
ITEM 3. LEGAL PROCEEDINGS AND ENVIRONMENTAL ISSUES
Litigation. We are subject to minor lawsuits incidental to operations in
the oil and gas industry. We believe we have meritorious defenses to all
lawsuits in which we are a defendant and will vigorously defend against them.
The resolution of these lawsuits, regardless of the outcome, will not have a
material adverse effect on our results of operations or financial position.
On July 28, 1998, JW Resources, Inc. brought suit against HSR and HSRTW,
Inc. in the United States District Court for the Northern District of Texas,
Amarillo Division (JW Resources, Inc. v. HS Resources, Inc. and HSRTW, Inc.,
Civil Action No. 2:98-CV-275). HSRTW, Inc. is now Questar Exploration and
Production Company, and is a subsidiary of Questar Corp. This case, which was
discussed in our report on Form 10-Q filed May 14, 1999, has now been settled
and dismissed with prejudice by the court and all significant costs are
reflected in the December 31, 1999 financial statements.
Environmental Proceedings. The owner of an oil field waste disposal
facility, a major oil company and HSR were named as respondents by the EPA in an
administrative order brought by the EPA against Weld
13
<PAGE> 14
County Waste Disposal, Inc. ("WCWDI") under section 7003 of the Resource
Conservation and Recovery Act 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. We and other
non-operators have been working together with the EPA to complete
characterization and closure of the facility. This work has been completed. We
have spent approximately $1.3 million to date on the project. This amount has
been recorded in our financial statements at December 31, 1999 and we believe
that no substantial liability remains.
On March 25, 1999, we voluntarily reported to the United States Corps of
Engineers the likely violation of Section 404 of the Clean Water Act in
connection with several of the HSR operated drillsites in southern Louisiana
where operations disturbed wetlands areas without the required advance
permitting. We agreed to promptly conduct wetlands delineations on all suspect
sites and to submit such data to the Corps for after-the-fact permitting. This
effort is now complete. The Corps issued a routine cease and desist order to HSR
prohibiting any further unpermitted wetlands disturbance on the violation sites.
This order does not interfere with continuation of production on producing
wells, but is delaying the hookup of two wells. This order does not affect our
operations on new wells. Responsibility for disposition of this matter has now
been transferred to Region 6 of the Environmental Protection Agency. We are
currently negotiating the settlement of this matter with the EPA and the United
States Department of Justice. We are unable at this time to be certain that the
matter will be settled, although we believe this is likely.
Finally, the gathering and transmission properties we are acquiring from
KMI contain numerous areas of polluted soil and ground water. These conditions
have been reported to the appropriate jurisdictional agencies. We expect the
costs associated with cleanup of these environmental problems will be borne by
KMI under the indemnification provisions of our agreement with them. See Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Contingencies."
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
14
<PAGE> 15
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
HSR's common stock is traded publicly on the NYSE under the symbol "HSE."
The following table presents the high and low sales prices reported by the NYSE
for the periods indicated. These prices do not include retail markups, markdowns
or commissions.
<TABLE>
<CAPTION>
QUARTER ENDED HIGH LOW
- - ------------- ---- ----
<S> <C> <C>
March 31, 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
March 31, 1998.............................................. 15 5/8 12 13/16
June 30, 1998............................................... 17 13 9/16
September 30, 1998.......................................... 15 1/4 7 1/2
December 31, 1998........................................... 11 15/16 6 1/4
March 31, 1999.............................................. 8 7/8 5 1/2
June 30, 1999............................................... 14 3/4 8 1/4
September 30, 1999.......................................... 17 1/4 13 1/8
December 31, 1999........................................... 17 1/4 12 1/2
</TABLE>
As of December 31, 1999, there were 560 holders of record of our common
stock.
We have never paid any cash dividends on our common stock, and our Board of
Directors does not currently intend to declare cash dividends on our common
stock. We instead intend to retain our earnings to support the growth of our
business. Any future cash dividends would depend on future earnings, capital
requirements and our financial condition and other factors deemed relevant by
the Board of Directors. Our credit facility currently prohibits payment of
dividends and the indentures governing our outstanding 9 1/4% and 9 7/8% senior
subordinated notes due in 2006 and 2003, respectively, also limit our ability to
pay dividends.
15
<PAGE> 16
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data, as of the dates and
for the periods indicated, and is qualified in its entirety by reference to the
consolidated financial statements of HS Resources, Inc. included herein. For
further discussion see Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations." This financial data reflects the
successful efforts method of accounting which we adopted December 31, 1998. See
Notes 1 and 2 to Consolidated Financial Statements.
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
1999 1998 1997 1996 1995
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND AVERAGE PRICES)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA
Revenues
Oil and gas sales.................. $164,660 $150,087 $137,251 $107,281 $ 53,394
Trading and transportation......... 52,662 54,144 90,062 46,373 --
Gathering and transmission system
revenues........................ 1,286 -- -- -- --
Other revenues..................... 10,742 9,965 6,392 3,302 1,946
-------- -------- -------- -------- --------
Total revenues............. 229,350 214,196 233,705 156,956 55,340
-------- -------- -------- -------- --------
Expenses
Production taxes................... 10,309 10,422 9,703 8,195 4,050
Lease operating.................... 28,014 30,410 24,848 17,692 9,936
Gathering and transmission system
operating expense............... 386 -- -- -- --
Cost of trading and
transportation.................. 49,567 50,451 88,402 45,699 --
Depreciation, depletion and
amortization.................... 54,400 61,223 45,757 36,600 24,577
Exploratory and abandonment........ 13,525 15,420 13,438 5,927 7,202
Geological and geophysical......... 6,837 14,308 17,049 4,262 3,509
Impairment and (gain)/loss on sales
of oil and gas properties....... (1,171) 11,986 15,710 2,909 (165)
General and administrative......... 5,823 8,061 11,550 8,497 5,613
Interest........................... 42,781 41,990 32,297 23,594 10,806
-------- -------- -------- -------- --------
Total expenses............. 210,471 244,271 258,754 153,375 65,528
-------- -------- -------- -------- --------
Income (loss) before provision
(benefit) for income taxes...... 18,879 (30,075) (25,049) 3,581 (10,188)
Provision (benefit) for income
taxes........................... 7,193 (11,459) (9,544) 1,364 (3,882)
-------- -------- -------- -------- --------
Net income (loss).................. $ 11,686 $(18,616) $(15,505) $ 2,217 $ (6,306)
-------- -------- -------- -------- --------
Diluted earnings (loss) per
share........................... $ 0.62 $ (1.00) $ (0.91) $ 0.15 $ (0.58)
-------- -------- -------- -------- --------
Weighted average number of common
shares outstanding assuming
dilution........................ 18,888 18,609 17,119 14,552 10,893
-------- -------- -------- -------- --------
BALANCE SHEET DATA
Working capital (deficiency)....... $(36,933) $(18,899) $ (8,329) $ 13,749 $(16,115)
Oil and gas properties, net........ 764,643 748,934 877,467 613,119 254,046
Gas gathering and transportation
facilities, net................. 52,611 4,274 4,541 4,674 4,914
Total assets....................... 911,178 832,439 956,306 695,644 277,324
Long-term debt..................... 560,140 534,917 636,699 398,563 125,537
Deferred income taxes.............. 53,246 44,138 61,933 72,487 15,406
Stockholders' equity............... 167,393 152,861 173,477 169,424 102,606
OPERATING DATA
Average sales price per barrel of
oil............................. $ 15.70 $ 14.58 $ 19.71 $ 20.90 $ 16.52
Average sales price per thousand
cubic feet of gas............... $ 2.16 $ 1.96 $ 2.19 $ 1.96 $ 1.30
PRODUCTION
Oil (Bbl).......................... 2,410 2,630 2,400 1,923 1,582
Gas (Mcf).......................... 58,799 56,969 41,125 34,163 21,049
Mcfe............................... 73,257 72,750 55,524 45,702 30,540
Boe................................ 12,210 12,125 9,254 7,617 5,090
NET CASH PROVIDED BY OPERATING
ACTIVITIES......................... $ 65,011 $ 60,505 $ 65,071 $ 38,549 $ 18,343
</TABLE>
16
<PAGE> 17
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
General. We have pursued a strategy centered around consolidation of assets
in the Denver-Julesburg ("D-J") Basin, coupled with continued exploitation and
exploration in our core areas. We use a technology-oriented approach to
exploitation and exploration designed to reduce risk and maximize efficiencies.
A major milestone in our D-J Basin consolidation was the December 1997
acquisition of all of Amoco Production Company's D-J Basin properties. This
transaction has also helped reshape our strategic direction, including in
particular, the September 1998 sale of our wholly-owned subsidiary, HSRTW, Inc.,
to Universal Resources Corp., a subsidiary of Questar Corp., for $157.5 million.
HSRTW, Inc. held the majority of our Mid-Continent assets.
In December 1999 we continued this consolidation strategy by acquiring
certain gas gathering and transmission assets (the "Wattenberg Gathering
System") from Kinder Morgan, Inc. ("KMI") for an adjusted purchase price of
approximately $48 million, plus the assumption of an operating lease which had a
net present value of $19 million. As part of this transaction, we also purchased
a 6.9% interest in the BP Amoco Wattenberg Gas Processing Plant, and a right of
first refusal to purchase the remaining interest in the plant. The transaction
is scheduled to close in December 2001. See Item 1. "Business -- Recent
Developments." The Wattenberg Gathering System consists of a low pressure
gathering system and a high pressure transmission system. The low pressure
gathering system consists of more than 1,500 miles of pipeline and 3,000
horsepower of compression, located in five northeastern Colorado counties. Gas
is delivered to the inlet of the high pressure transmission system, which
consists of almost 60 miles of high pressure pipeline and almost 40,000
horsepower of compression. The acquisition is recorded in our financial
statements using the purchase method of accounting. This purchase has given us
operational control over the gathering of a large percentage of our gas
production, and provides the infrastructure to achieve increased future market
presence. By operating the pipeline we will be better positioned to anticipate
and alleviate any gathering system bottlenecks that otherwise might have
adversely affected our D-J Basin exploitation program and the production of
other operators.
To complete the Amoco acquisition we were required to borrow funds, which
significantly increased our leverage ratios. To partially reduce this increase
in debt we sold the majority of our Mid-Continent asset base and utilized the
proceeds to pay down debt under our senior credit facility. See "Liquidity and
Capital Resources -- Financing Sources." Following the Mid-Continent sale, we
now operate primarily in three core areas: the D-J Basin, the Gulf Coast and, to
a lesser extent, the Northern Rockies. In 1999, approximately 90% of our
production (on an energy equivalent basis) came from the D-J Basin and 10% from
the Gulf Coast. We will continue to pursue certain technology-oriented
exploration projects and other activities in other regions, including the
Mid-Continent. We will also continue our strategically important and
historically profitable presence in the gas marketing, trading and
transportation business through our wholly-owned subsidiary, HS Energy Services,
Inc. ("HSES"). HSES provides opportunities for us to enhance our operating
margins on gas production from each of our producing areas and from production
we market on behalf of other oil and gas producers.
Oil And Gas Prices. Profitability in the United States oil and gas industry
fluctuates widely due in part to fluctuating commodity prices and related
changes in rates of reinvestment by industry participants. In early 1999, United
States natural gas prices and international crude oil prices were very low,
resulting in significant reductions in the operating and financial margins of
oil and gas producers. Additionally, low oil prices had a depressing effect on
the price of liquids recovered from natural gas during this time period. Thus,
the early 1999 low oil price environment further diminished the overall price
received for our gas production. As a result of these factors, the weighted
average price we realized per barrel of oil, excluding hedging effects for the
three months ended March 31, 1999 was $11.43 compared to $14.77 for the
comparable period in 1998. Natural gas prices per Mcf, excluding hedging
effects, were $1.68 for the three months ended March 31, 1999, compared to $2.16
in the comparable period in 1998. In April 1999, both oil and gas prices began
to recover, particularly as compared to the prior year when prices were
declining. This resulted in HSR realizing for the three months ended December
31, 1999 an average price per barrel of oil, excluding hedging effects, of
$22.98 compared to $11.18 for the comparable period in 1998. Natural gas
17
<PAGE> 18
prices per Mcf, excluding hedging effects, were $2.63 for the three months ended
December 31, 1999 compared to $1.81 in the comparable period in 1998.
At December 31, 1999, approximately 82% of our proved producing reserves
consisted of gas, of which 97% were located in the D-J Basin. The absolute level
and volatility of gas prices, particularly in the D-J Basin, have a material
impact on HSR. Historically, the price of D-J Basin gas (on a Btu-equivalent
basis) has been linked closely to the Colorado Interstate Gas Company ("CIG")
pipeline Rocky Mountain Index. This remains the case during the lower demand
summer months (generally April through October). More recently, however, as a
result of increased pipeline capacity into and out of the D-J Basin, a
transportation cost advantage for deliveries into the Public Service Company of
Colorado ("PSCO") Front Range market, and seasonal fluctuations, the price more
closely tracks Mid-Continent indices during the higher demand winter periods
(generally November through March).
In the fall of 1998, PSCO and CIG, through a jointly owned affiliate, began
operating a newly expanded 270 MMcfd capacity line between the Colorado Front
Range market area and Wyoming. This line operates independently and not as part
of PSCO's local distribution system. Additionally, KMI has been granted
authority to build a 250 MMcfd capacity pipeline serving similar regions.
Construction has not commenced on the KMI line, and it is uncertain whether this
line will be built in the near future. The PSCO line is expected to eliminate
some portion of the price advantage HSR currently has over Wyoming producers for
direct sales in the Colorado Front Range market as it increases the amount of
Wyoming gas that could be transported to the Colorado Front Range market.
However, the availability of one or both of these lines also expands the amount
of gas that could be exported from the D-J Basin to Mid-Continent and West Coast
markets through Wyoming pipeline interconnections. To date, the increased export
capacity from the D-J Basin on the PSCO line, combined with increased demand
from and transportation to West Coast markets out of Wyoming, have strengthened
the overall market for D-J Basin gas compared to several years ago. Given the
narrowing of the spread between CIG and Mid-Continent indices, we do not
anticipate any material adverse changes to D-J Basin gas prices as a result of
the new pipelines.
Gas and oil prices remain strong as of the date of this report. However, we
cannot predict future trends in gas or oil prices. The uncertainty concerning
the price of oil and gas remains a dominant and unpredictable factor in our
profitability.
Results Of Operations. During 1999 we continued our drilling and
development activities to exploit our opportunities in the D-J Basin. We also
continued our exploitation and exploration activities in the Gulf Coast region.
Our results of operations are significantly affected by our drilling program and
by fluctuations in oil and gas prices. Future results will be significantly
affected by our exploration, exploitation and development activities.
18
<PAGE> 19
Comparative operating results by business segment, consolidated other
income, expenses and income taxes are presented below. Segment operating
revenues, costs and expenses are before intersegment eliminations.
COMPARISON OF YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
D-J BASIN
OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES)
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- -------
<S> <C> <C> <C>
Production:
Oil (Bbl)................................................. 2,159 2,382 1,957
Gas (Mcf)................................................. 53,066 48,628 24,871
Mcfe...................................................... 66,018 62,920 36,612
Boe....................................................... 11,003 10,487 6,102
Prices(1):
Average realized oil price ($/Bbl)........................ $ 15.33 $ 14.78 $ 19.78
Average realized gas price ($/Mcf)........................ $ 2.11 $ 1.96 $ 2.15
Operating Revenues:
Oil and gas sales......................................... $145,037 $130,601 $92,067
Other gas revenues........................................ 10,132 8,658 4,290
-------- -------- -------
155,169 139,259 96,357
-------- -------- -------
Operating Costs and Expenses:
Production taxes.......................................... 9,206 9,120 6,376
Lease operating........................................... 27,139 25,938 17,273
Depreciation, depletion and amortization.................. 49,655 50,735 23,147
Exploratory and abandonment............................... 952 1,188 1,582
Geological and geophysical................................ 307 1,892 835
Impairment and (gain)/loss on sales of oil and gas
properties............................................. 71 (1,152) --
-------- -------- -------
87,330 87,721 49,213
-------- -------- -------
Operating Income............................................ $ 67,839 $ 51,538 $47,144
======== ======== =======
</TABLE>
- - ---------------
(1) Includes effects of hedging activities.
General. We have been active in the D-J Basin for almost 20 years. Over the
years we sought to consolidate our position there by acquiring properties and
conducting active exploitation programs. More recent acquisitions include the
June 1996 acquisition of Basin Exploration, Inc.'s D-J Basin properties, the
December 1997 Amoco acquisition, and the 1999 acquisition of the Wattenberg
Gathering System. The 1999 and 1998 exploitation programs consisted of 397 and
450 separate activities, respectively.
Oil And Gas Revenues. Over the past three years, our D-J Basin oil and gas
production and revenues have increased primarily as the result of acquired
properties and the success of our ongoing exploitation and development
activities. As a result of the increased production, other gas revenues related
to the sale of tax credits also increased during the same period.
Production Expenses. Total lease operating expense ("LOE") increased from
1997 to 1998 and from 1998 to 1999 due to a larger number of producing wells in
1998 and an increase in workover costs and COPAS charges in 1999. The increase
in COPAS charges was due to an increase in the COPAS escalation factor as of
April 1, 1999 in accordance with COPAS guidelines. Despite the higher total
costs, LOE per Mcfe declined from $0.47 in 1997 to $0.41 in 1998 and 1999
because the increases in total costs were offset by an increase in production.
Production taxes increased from 1998 to 1999 as a result of higher realized oil
and gas prices in 1999. The higher taxes were offset partially by adjustments we
recorded in the second quarter to reduce the ad valorem tax accrual rate for
1998 and 1999 to the rate actually paid in 1999. An
19
<PAGE> 20
adjustment of $1.7 million was also recorded in the last quarter of 1999 for ad
valorem tax abatements associated with the 1996, 1997 and 1998 tax years. The
production tax increase from 1997 to 1998, due to increased production, was
partially offset by decreased product prices.
Depreciation, Depletion And Amortization. Depreciation, depletion and
amortization ("DD&A"), a non-cash expense, increased from 1997 to 1998 due to an
increase in production and an increase in the depletion rate, resulting in part
from certain proved reserves being written-off due to lower year-end product
prices. DD&A decreased from 1998 to 1999 as a result of a decrease in the
depletion rate due to the addition of proved reserves as a result of higher
year-end product prices. The weighted average depletion rate per Mcfe for the
D-J Basin was $0.75, $0.80, and $0.62 ($4.47, $4.81 and $3.74 per Boe) for the
years ended December 31, 1999, 1998 and 1997, respectively. We annually adjust
our DD&A rate based on year-end engineering and, if material changes in our
reserves warrant, on an interim basis.
Exploratory And Abandonment Costs. Exploratory and abandonment costs
include the costs of exploratory dry holes, delay rentals, plugging and
abandonment ("P&A") costs, expired acreage and salaries and related overhead
("overhead") costs directly related to exploratory activities. Exploratory and
abandonment costs decreased from 1997 to 1998 and from 1998 to 1999 mainly due
to a decrease in exploratory dry hole costs.
Geological And Geophysical Costs. Geological and geophysical ("G&G") costs
include costs for seismic activity as well as overhead costs directly
attributable to G&G activity. Of the total G&G costs, we incurred $0.1 million,
$1.4 million and $0.5 million in seismic costs for the years ended 1999, 1998
and 1997, respectively. The remaining G&G costs of $0.2 million, $0.5 million
and $0.3 million relate to overhead costs directly attributable to G&G activity.
The increase in 1998 compared to the prior year relates to an increase in 3-D
seismic activity in the Greater D-J Basin area. This 3-D seismic activity was
dramatically reduced in 1999.
Impairment And (Gain)/Loss On Sales Of Oil And Gas Properties. In 1998, we
recorded a gain on the sale of 93 wells, for $2.9 million in cash, located
primarily in the Yuma County area of the D-J Basin.
GULF COAST
OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES)
<TABLE>
<CAPTION>
1999 1998 1997
------- -------- --------
<S> <C> <C> <C>
Production:
Oil (Bbl)................................................. 251 30 22
Gas (Mcf)................................................. 5,566 883 478
Mcfe...................................................... 7,072 1,061 607
Boe....................................................... 1,179 177 101
Prices(1):
Average realized oil price ($/Bbl)........................ $ 18.90 $ 11.99 $ 19.05
Average realized gas price ($/Mcf)........................ $ 2.63 $ 2.25 $ 2.81
Operating Revenues:
Oil and gas sales......................................... $19,365 $ 2,344 $ 1,754
Operating Costs and Expenses:
Production taxes.......................................... 1,047 131 103
Lease operating........................................... 662 160 20
Depreciation, depletion and amortization.................. 3,158 510 274
Exploratory and abandonment............................... 11,530 9,127 6,570
Geological and geophysical................................ 5,670 10,826 15,052
Impairment and loss on sales of oil and gas properties.... -- 1,061 --
------- -------- --------
22,067 21,815 22,019
------- -------- --------
Operating Loss.............................................. $(2,702) $(19,471) $(20,265)
======= ======== ========
</TABLE>
- - ---------------
(1) There were no hedging activities affecting Gulf Coast production in 1999.
20
<PAGE> 21
General. Over the past several years, the majority of our Gulf Coast
activities focused on acquiring, processing and interpreting 3-D seismic
information, acquiring leasehold interests, and drilling on our project areas.
During 2000 we expect to continue to increase our level of Gulf Coast drilling
activities on prospects that we have identified through our 3-D seismic
programs.
Oil And Gas Revenues. Oil and gas revenues increased significantly in 1999
compared to 1998 due to an increase both in production and in oil and gas
prices. Oil and gas revenues remained relatively flat between 1997 and 1998
because the increase in production was partially offset by a decrease in product
prices. We drilled a total of 26 gross (11.2 net) wells in 1999, 24 gross (6.7
net) wells in 1998 and 16 gross (2.6 net) in 1997. Of the total wells drilled to
date, 5 gross (2.25 net) are currently awaiting pipeline hookup.
Production Expenses. Aggregate LOE increased from 1998 to 1999 because of
the greater number of producing wells but LOE per Mcfe decreased from $0.15 in
1998 to $0.09 in 1999 because the increase in aggregate LOE was more than offset
by the production increase. Production taxes increased from 1998 to 1999 as a
result of increases in both production and product prices.
Depreciation, Depletion And Amortization. Total DD&A increased from 1998
compared to 1999 mainly as a result of an increase in production. However, the
weighted average DD&A rate per Mcfe in the Gulf Coast declined from $0.48 in
1998 to $0.45 in 1999.
Exploratory And Abandonment Costs. During 1999 we incurred $4.8 million for
11 exploratory dry holes, $4.3 million for expired acreage, $1.4 million for
delay rentals and $1.0 million for overhead costs. In 1998, we incurred $5.8
million for expired acreage in our Gulf Coast project areas, $0.8 million in
delay rentals, $1.0 million for seven exploratory dry holes and $1.6 million for
overhead costs directly related to exploratory activities. In 1997, we incurred
$3.4 million for eight exploratory dry holes, $1.8 million for expired acreage,
$0.6 million for delay rentals and $0.7 million for overhead costs.
Geological And Geophysical Costs. Of total G&G costs, we incurred $4.5
million, $9.4 million and $13.8 million in 1999, 1998 and 1997, respectively,
for seismic permits and processing costs in the Gulf Coast. The remaining G&G of
$1.1 million, $1.5 million and $1.2 million relates to overhead costs directly
attributable to G&G activity.
Impairment And Loss On Sales Of Oil And Gas Properties. In 1998, we
recorded a loss on the sale of two wells. The wells were conveyed in a non-cash
transaction to a third party purchaser which assumed liability for plugging and
abandonment costs.
21
<PAGE> 22
MID-CONTINENT AND NORTHERN ROCKIES
OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES)
<TABLE>
<CAPTION>
1999 1998(1) 1997
------- -------- -------
<S> <C> <C> <C>
Production:
Oil (Bbl)................................................. -- 218 421
Gas (Mcf)................................................. 166 7,459 15,777
Mcfe...................................................... 166 8,768 18,305
Boe....................................................... 28 1,461 3,051
Prices(2):
Average realized oil price ($/Bbl)........................ $ -- $ 12.80 $ 19.44
Average realized gas price ($/Mcf)........................ $ 1.51 $ 1.92 $ 2.23
Operating Revenues:
Oil and gas sales......................................... $ 258 $ 16,983 $43,430
Other gas revenues........................................ -- 62 159
------- -------- -------
258 17,045 43,589
------- -------- -------
Operating Costs and Expenses:
Production taxes.......................................... 55 1,172 3,224
Lease operating........................................... 213 4,311 7,555
Depreciation, depletion and amortization.................. 70 8,042 20,290
Exploratory and abandonment............................... 1,043 5,104 5,287
Geological and geophysical................................ 860 1,591 1,162
Impairment and (gain)/loss on sales of oil and gas
properties............................................. (1,241) 12,077 15,709
------- -------- -------
1,000 32,297 53,227
------- -------- -------
Operating Loss.............................................. $ (742) $(15,252) $(9,638)
======= ======== =======
</TABLE>
- - ---------------
(1) Results for production, operating revenues and associated expenses through
date of sale, September 1, 1998.
(2) There were no hedging activities affecting Mid-Continent and Northern
Rockies production in 1999.
General. Information for this segment includes activity for both the
Mid-Continent and Northern Rockies areas. Effective September 1, 1998, we sold
our Mid-Continent assets and used the proceeds from the sale to pay down a
portion of debt under our senior credit facility. Our current strategy in the
Mid-Continent is to pursue technology-oriented exploration projects.
Over the past seven years we have acquired extensive acreage in the
Northern Rockies region. Our current strategy is to utilize our acreage position
as a vehicle for generating capital expenditures by third party operators on our
acreage.
Oil And Gas Revenues. Because our Mid-Continent properties were sold
effective September 1998, our 1997 production and revenues reflect a full year
of activity, while the 1998 numbers reflect only a partial year. Product prices
also declined significantly from 1997 to 1998. In 1999 there were virtually no
oil and gas revenues in this segment because of the earlier Mid-Continent
property sale and the sale of properties in the Northern Rockies region.
Production Expenses. LOE per Mcfe increased in the Mid-Continent for the
eight months of activity in 1998 compared to a full year of activity in 1997,
due primarily to an increase in compressor expenses. We sold our compressors in
June 1998 because of extensive repairs required in order to maintain them. For
the period June 1998 through August 1998, we leased compressors at a higher
cost. Production taxes decreased in the Mid-Continent in 1998 compared to 1997
as a result of the fluctuation in revenues discussed above.
22
<PAGE> 23
Depreciation, Depletion And Amortization. Aggregate DD&A decreased in 1998
compared to 1997 due to a decrease in production and a decrease in the depletion
rate. The weighted average depletion rate per Mcfe for the Mid-Continent was
$0.92 and $1.12 ($5.52 and $6.70 per Boe) for the years ended December 31, 1998
and 1997, respectively.
Exploratory And Abandonment Costs. The majority of exploratory and
abandonment costs for 1999, 1998 and 1997 represent costs incurred for expired
acreage, delay rentals and capitalized interest for projects in the Northern
Rockies.
Geological And Geophysical Costs. The decrease in G&G costs in 1999
compared to 1998 is the result of less seismic activity in the Northern Rockies
project area. The majority of the costs incurred in 1998 and 1997 relate to G&G
activity on projects in the Northern Rockies.
Impairment And (Gain)/Loss On Sales Of Oil And Gas Properties. In 1999 we
recorded additional expenses of $2.2 million related to the 1998 sale of the
Mid-Continent properties, and income from the sale of the Blue Forest unit and
other properties of $3.4 million. In 1998 and 1997, we recorded impairments of
$5.0 million and $1.6 million, respectively on properties in the Northern
Rockies region. We recorded a loss on the sale of Mid-Continent properties of
$7.0 million and $14.1 million in 1998 and 1997, respectively. The loss reported
in 1997 did not result from a cash sale, but stemmed from the value assigned to
certain Mid-Continent properties which were exchanged in connection with the
Amoco acquisition.
TRADING AND TRANSPORTATION
(IN THOUSANDS)
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Operating Revenues:
Trading and transportation(1)............................ $170,232 $142,374 $148,994
Operating Costs and Expenses:
Cost of trading and transportation(1).................... 164,665 136,245 146,652
Depreciation and amortization............................ 434 416 382
-------- -------- --------
165,099 136,661 147,034
-------- -------- --------
Operating Income........................................... $ 5,133 $ 5,713 $ 1,960
======== ======== ========
</TABLE>
- - ---------------
(1) Intercompany revenues and expenses attributable to our volumes which are
marketed by HSES have been eliminated in our consolidated financial
statements.
Through our wholly-owned subsidiary, HSES, we market our own gas production
as well as that of third parties. A portion of this gas is sold directly to end
users, while other amounts are used as the equity-gas foundation for a physical
trading business in which gas volumes may be traded several times at different
receipt and delivery points in order to capture the greatest margin possible.
HSES also serves as an intermediary in the execution of financial derivative
instruments for a variety of energy related products and, to a lesser extent,
makes speculative trades for its own account in the commodity and basis markets.
Operating margins increased in 1999 and 1998 compared to 1997 primarily as a
result of an increase in the volume of financial intermediary transactions and
gains recorded by HSES in commodity and basis trading activities. For the years
ended December 31, 1999, 1998 and 1997, gains of $3.3 million, $2.8 million and
$0.5 million, respectively were recognized in connection with financial trading
activities.
23
<PAGE> 24
OTHER INCOME AND EXPENSES
(IN THOUSANDS)
<TABLE>
<CAPTION>
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Gathering and transmission system revenues.................. $ 1,286 $ -- $ --
Interest income and other................................... $ 610 $ 1,405 $ 1,943
General and administrative.................................. $ 5,823 $ 8,061 $11,550
Interest.................................................... $42,781 $41,990 $32,297
Depreciation................................................ $ 1,083 $ 1,520 $ 1,664
Gathering and transmission system operating expense......... $ 386 $ -- $ --
</TABLE>
Gathering And Transmission System Revenues And Expenses. Effective December
1, 1999 we took over operations of the Wattenberg Gathering System from KMI. The
revenues and expenses associated with third party gas for the month of December
1999 are recorded as gathering and transmission system revenues and expenses.
Interest Income And Other Income. Interest and other income decreased from
1998 to 1999. As a result of the Mid-Continent sale we no longer record income
on an interest in a limited partnership. Interest and other income decreased
from 1997 to 1998 due to a decrease in funds available for short-term investing.
General And Administrative Expenses. General and administrative expenses
("G&A") reflect costs incurred, net of administrative costs directly
attributable to drilling and well operations (which costs are included in LOE).
G&A costs directly related to geological and geophysical activities and
exploratory activities are included in geological and geophysical costs and
exploratory costs. G&A per Mcfe was $0.08, $0.11 and $0.21 ($0.48, $0.66 and
$1.25 per Boe) in 1999, 1998 and 1997, respectively. On both an absolute and an
Mcfe basis, G&A decreased from 1997 to 1998 and 1998 to 1999. The decrease from
1998 to 1999 was due primarily to discontinued G&A related to our Mid-Continent
properties and the efficiencies associated with our consolidation program in the
D-J Basin. The decrease from 1997 to 1998 was due to efficiencies gained from
consolidating the Amoco properties and the timing of hiring additional personnel
to service these properties, and as a result of discontinued G&A attributable to
our Mid-Continent properties sold in 1998.
Interest Expense. Interest expense increased from 1998 to 1999 due to a
full year of interest payments on the $85 million senior subordinated notes
issued in December 1998, a decrease in capitalized interest as a result of a
reduction in the undeveloped acreage account and interest associated with the
1999 purchase of the Wattenberg Gathering System. Interest expense increased
from 1997 to 1998 due to the increase in long-term debt attributable to amounts
borrowed in December 1997 to fund the Amoco acquisition. During 1999, 1998 and
1997 we capitalized $7.1 million, $11.7 million and $3.8 million, respectively
of interest relating to undeveloped acreage.
INCOME TAXES
(IN THOUSANDS)
<TABLE>
<CAPTION>
1999 1998 1997
------- -------- --------
<S> <C> <C> <C>
Current provision (benefit)................................. $(2,100) $ 5,300 $ 900
Deferred provision (benefit)................................ 9,293 (16,759) (10,444)
------- -------- --------
Provision (benefit) for taxes............................... $ 7,193 $(11,459) $ (9,544)
======= ======== ========
Effective tax rate.......................................... 38.1% 38.1% 38.1%
======= ======== ========
</TABLE>
Provision For Income Taxes. We follow the provisions of Statement of
Financial Accounting Standards ("SFAS") No. 109. Pursuant to SFAS 109, we have
recorded a tax provision based on tax rates in effect during the period.
Accordingly, we accrued taxes at the rate of 38.1% in 1999, 1998 and 1997. Due
primarily
24
<PAGE> 25
to significant intangible drilling costs, which are deductible for income tax
purposes, substantially all of our tax provision in 1997 and 1999 is deferred.
In 1998, the current provision is attributable to taxes owed in connection with
the sale of our Mid-Continent properties.
LIQUIDITY AND CAPITAL RESOURCES
Financing Sources. We believe that our current level of debt is manageable
under expected production and pricing levels because our debt is supported by
stable, long-lived producing reserves and by short-term product prices that are
partially hedged at prices that support our bank and other interest
requirements. We expect cash flows from producing activities to be sufficient to
enable us to service our debt for the foreseeable future, absent any major and
prolonged period of low commodity prices or sustained production interruptions.
We have a large number of low-risk, potentially high-return exploitation
projects which should enhance production and cash flow. As part of an overall
financing strategy, we continually evaluate a wide range of future financing
alternatives and are not committed to any particular course. In undertaking any
future financing transactions, we will seek to achieve the optimal capital
structure needed to support our long-term strategic objectives. Any such
financings will reflect market conditions at the time and may include the
issuance of medium or long-term debt, equity, or equity-linked securities.
We currently plan to fund capital expenditures attributable to exploration,
exploitation and development activities primarily out of our expected cash flow
from operations, subject to periodic variation resulting from the timing of
project activities and short-term product price volatility.
The borrowing base under our revolving senior bank credit facility led by
The Chase Manhattan Bank is currently $280.0 million. The interest rate under
the Chase facility is the Base Rate plus 0% to 0.625% or LIBOR plus 0.75% to
1.625%. The borrowing base is based on the Banks' review of our reserves and the
Banks' view of future pricing. Under the terms of the Chase facility, no
principal payments are required until December 15, 2002, assuming we maintain a
borrowing base sufficient to support the outstanding loan balance. As of
December 31, 1999, $227.0 million was outstanding under the Chase facility
compared to $230.0 million at December 31, 1998.
We anticipate that our borrowing capacity under the Chase facility and our
operating cash flow will provide us with adequate financial resources and
flexibility to fund current and ongoing activities, to service our debt and to
meet other financial obligations. The nature of our current development
strategies and other activities provide us with considerable flexibility in
terms of the timing and magnitude of our capital expenditures. If we experience
unforeseen changes in our working capital position or capital resources, we may
revise the capital expenditure program accordingly or alternatively may attempt
to supplement our capital position through, among other things, the issuance of
additional equity, equity-linked or debt securities, the sale or monetization of
properties or by entering into joint venture arrangements.
Capital Commitments. We continuously evaluate our inventory of drilling
opportunities to develop a growth-oriented portfolio of risk-balanced
development, exploitation and exploration opportunities. On an ongoing basis, we
adjust the amount and allocation of our capital expenditures based on a number
of factors, including seismic results, prospect readiness, product prices,
service company availability and rates, acquisitions and capital position. For
the year ended December 31, 1999, we incurred total costs for exploration,
development, leasehold, exploratory and abandonment and geological and
geophysical activities of $80.2 million, exclusive of capitalized interest and
overhead costs directly related to exploratory and G&G activity. We estimate
that such expenditures for the year 2000 will be approximately $100 to $110
million, depending on product prices for the full year. These costs will be
allocated in varying amounts primarily to activities in our core geographic
areas.
A major component of our capital program relates to our development
activities in the D-J Basin. We incurred approximately $50.8 million for the
year ended December 31, 1999 for costs to drill, deepen, recomplete and refrac
our D-J Basin properties, and we anticipate allocating approximately $55 to $60
million to the D-J Basin during 2000.
25
<PAGE> 26
Another component of our capital program has been to develop our
exploitation and exploration prospects in the onshore portion of the Gulf Coast.
For the year ended December 31, 1999, we incurred total expenditures of $26.5
million for seismic, leasehold and drilling costs in the Gulf Coast. We
anticipate allocating approximately $25 to $40 million to the Gulf Coast
projects during 2000 for exploration and development activities including land
and seismic.
Activities in the Northern Rockies are planned to manage risk by utilizing
our extensive acreage positions, operational expertise, and geotechnical ideas
to attract risk capital from value-added partners. We believe our projects have
substantial flexibility in terms of timing, as a result of long-term leases and
minimal future capital obligations.
We have also entered into a number of other standard industry arrangements
that require the drilling of wells or other activities. We believe that we will
meet our obligations under these arrangements, which individually and in the
aggregate are not material.
Working Capital And Cash Flow. The Company aggressively manages its working
capital position including periodic borrowings and repayments under its
revolving credit facility. Of the total working capital deficit of $36.9 million
at December 31, 1999, $19.6 million represents the current portion of the
payable to KMI for the purchase of the Wattenberg Gathering System. The Company
intends to use cash provided by monthly gathering and transportation revenues
from existing contractual agreements, including amounts paid by HSR, to fund the
monthly obligations to KMI. The Company believes that the payments made under
the gathering agreements will exceed the payments to KMI assuming no unforeseen
extended operational interruptions of the system.
Net cash provided by operating activities for the year ended December 31,
1999 was $65.0 million, up from $60.5 million for the same period in 1998
primarily as a result of an increase in product prices and an overall reduction
in expenses. Future cash flows will be influenced by, among other factors, the
number of producing wells on line, product prices and production constraints.
Risk Management. We use financial instruments to reduce our exposure to
market fluctuations in the price and transportation cost of oil and gas. Our
general strategy is to hedge price and location risk with swap, collar, floor
and ceiling arrangements. In order to minimize risk, we hedge certain of our
production back to the well head. In addition to hedging activities, we are
engaged in using the financial markets to capture trading margins. We have
established policies with respect to open positions which limit our exposure to
market risk and require daily reporting to management of the potential financial
exposure resulting from both hedging and trading activities.
Recently issued accounting pronouncements can change current and future
accounting and reporting requirements for certain risk management activities.
See Note 2 of the Notes to Consolidated Financial Statements.
Hedging Activities. We enter into transactions for hedging purposes to
manage our exposure to price and location risks in the marketing of our oil and
gas production and, in the case of our marketing activities, third party gas.
Gains and losses on hedging positions are recognized in the period during which
the underlying physical transactions occur and are booked in "oil and gas sales"
(for company-owned production) and "trading and transportation revenues" (for
third party gas). Hedging contracts for our production reduced our oil and gas
sales by $6.1 million in 1999 and by $2.9 million in 1997 and increased our oil
and gas sales by $9.0 million in 1998. Hedging contracts for third party gas
increased trading and transportation revenues by approximately $36,000, $346,000
and $1.2 million in 1999, 1998 and 1997, respectively.
As a part of our risk management program, we generally enter into hedges
for delivery into one of several pipelines located near our producing regions,
Panhandle Eastern Pipeline Company ("PEPL"), Northwest Pipeline Corporation
("NW"), CIG, or at the New York Mercantile Exchange ("NYMEX") prices settled at
the Henry Hub. With respect to the NYMEX-hedged volumes that exceed our Gulf
Coast volumes, it is our practice to hedge our basis (meaning the transportation
differential from our producing regions to the location of delivery for a hedged
volume).
26
<PAGE> 27
As of December 31, 1999, we held hedge swap positions as follows:
GAS HEDGES
<TABLE>
<CAPTION>
AVERAGE DAILY FAIR VALUE AT
QUANTITY SETTLEMENT PRICE DECEMBER 31, 1999
TIME PERIOD (MMBTU) LOCATION (PER MMBTU) GAIN (LOSS)
- - ----------- ------------- ---------- ----------- -----------------
<S> <C> <C> <C> <C>
January 2000-March 2000................... 10,000 PEPL $2.490 $233,375
January 2000-March 2000................... 5,000 PEPL $2.520 $130,338
January 2000-March 2000................... 20,000 PEPL $2.700 $848,950
January 2000-March 2000................... 10,000 NW $2.175 $(15,175)
April 2000-October 2000................... 15,000 NW $2.200 $426,177
April 2000-October 2000................... 5,000 NW $2.200 $142,059
April 2000-October 2000................... 10,000 NW $2.250 $391,118
January 2000-January 2000................. 25,000 NYMEX $2.405 $ 47,275
January 2000-January 2000................. 15,000 NYMEX $2.250 $ 17,903
February 2000-February 2000............... 15,000 NYMEX $2.360 $ 13,485
February 2000-February 2000............... 25,000 NYMEX $2.205 $ 4,350
March 2000-March 2000..................... 15,000 NYMEX $2.400 $ 37,200
March 2000-March 2000..................... 25,000 NYMEX $2.245 $ 62,000
January 2000-February 2000................ 20,000 NYMEX $2.435 $117,900
March 2000-March 2000..................... 20,000 NYMEX $2.465 $ 89,900
April 2000-October 2000................... 10,000 NYMEX $2.198 $278,768
April 2000-October 2000................... 25,000 NYMEX $2.150 $442,795
April 2000-October 2000................... 10,000 NYMEX $2.115 $102,218
April 2000-October 2000................... 30,000 NYMEX $2.052 $(94,596)
November 2000-March 2001.................. 20,000 NYMEX $2.195 $203,240
April 2001-October 2001................... 10,000 NYMEX $2.090 $ 55,540
April 2001-October 2001................... 20,000 NYMEX $2.110 $196,680
</TABLE>
WRITTEN GAS CALLS
<TABLE>
<CAPTION>
AVERAGE DAILY FAIR VALUE AT
QUANTITY SETTLEMENT PRICE DECEMBER 31, 1999
TIME PERIOD (MMBTU) LOCATION (PER MMBTU) GAIN (LOSS)
- - ----------- ------------- ---------- ----------- -----------------
<S> <C> <C> <C> <C>
January 2000-December 2000................ 20,000 NYMEX $3.100 $(338,066)
January 2001-December 2001................ 20,000 NYMEX $3.000 $(752,538)
</TABLE>
As of December 31, 1999 we had hedged our expected oil production as
follows:
CRUDE HEDGES
<TABLE>
<CAPTION>
AVERAGE MONTHLY FAIR VALUE AT
QUANTITY SETTLEMENT PRICE DECEMBER 31, 1999
TIME PERIOD (BBL) LOCATION (PER BBL) GAIN (LOSS)
- - ----------- --------------- ---------- --------- -----------------
<S> <C> <C> <C> <C>
January 2000-March 2000.................. 30,333 WTI $13.300 $(1,023,790)
January 2000-March 2000.................. 151,667 WTI $23.950 $ (273,198)
April 2000-June 2000..................... 61,333 WTI $22.600 $ 33,643
</TABLE>
WRITTEN CRUDE CALLS
<TABLE>
<CAPTION>
AVERAGE MONTHLY FAIR VALUE AT
QUANTITY SETTLEMENT PRICE DECEMBER 31, 1999
TIME PERIOD (BBL) LOCATION (PER BBL) GAIN (LOSS)
- - ----------- --------------- ---------- --------- -----------------
<S> <C> <C> <C> <C>
January 2000-December 2000............... 61,000 WTI $21.400 $(1,703,129)
January 2001-December 2001............... 60,833 WTI $20.400 $(1,141,401)
</TABLE>
27
<PAGE> 28
Additionally, with respect to the hedging of third party gas, we have
hedged 3.3 Bcf from January 2000 through December 2000 with offsetting physical
positions at settlement prices which are based upon NYMEX future prices or other
published indices. The fair market value of these hedges at December 31, 1999
was a gain of $95,026.
We routinely buy and sell options or forward contracts as part of our
overall hedging strategy. As of December 31, 1999, we had written crude and
natural gas calls through December 2001. These calls are hedged by future
production. The counterparties to these call transactions require the
maintenance of specified margin balances. Fluctuations in the mark-to-market
value of these instruments could result in additional margin requirements over
the term of the underlying contracts.
Trading Activities. We engage in the trading of various energy related
financial instruments which require payments to (or receipt of payments from)
counterparties based on the differential between a fixed and a variable price
for the commodity, swap or other contractual arrangement. Activities for trading
purposes are accounted for using the mark-to-market method. Under this method,
changes in the market value of outstanding financial instruments are recognized
in "trading and transportation revenues" as a net gain or loss in the period of
change. The market prices used to value these transactions reflect management's
best estimate considering various factors, including closing exchange and
over-the-counter quotations, time value and volatility factors underlying the
commitments. The values are adjusted to reflect the potential impact of
liquidating our position in an orderly manner over a reasonable period of time
under present market conditions.
Our policy requires that, within defined trading limits, financial
instrument purchase and sales contracts be balanced in terms of contract volumes
and the timing of performance and delivery obligations. For the years ended
December 31, 1999, 1998 and 1997, net gains of $3.3 million, $2.8 million and
$0.5 million, respectively, were recognized in connection with financial trading
activities and are included in "trading and transportation revenues."
Credit Risk. While notional amounts are used to express the volume of
various derivative financial instruments, the amounts potentially subject to
credit risk in the event of nonperformance by the third parties are
substantially smaller. Counterparties to the swap, collar, floor and ceiling
arrangements discussed above are generally investment grade institutions.
Accordingly, we do not anticipate any material impact to our financial position
or results of operations as a result of nonperformance by the third parties to
financial instruments related to hedging activities or trading activities.
Interest Rate Swaps. In the first quarter of 1999, we entered into an
interest rate exchange agreement with a financial institution to hedge $50
million of our borrowings at 5.66% through March 31, 2004. During the fourth
quarter of 1998, we entered into an interest rate exchange agreement with a
financial institution to hedge the interest rate on $80 million of our
borrowings at 5.86% through December 15, 2006. Under the terms of the
agreements, the difference between the fixed rate and the one-month LIBOR rate
is received or paid by us. As part of the $80 million hedging agreement, we
cancelled or offset our pre-1999 interest rate hedging agreements. Market risk
related to borrowings from a one percent change in interest rates would result
in an approximate $1.0 million impact on pre-tax income, based on the year end
borrowing level and the amount of such borrowings which are not subject to
interest rate swaps.
Total Return Equity Swaps. In 1999 we entered into three total return
equity swap agreements with financial institutions. Under the terms of the first
agreement, entered into on February 25, 1999, the financial institution acquired
approximately 730,000 shares of HSR's common stock from another investor at a
price of $6.0625. We have the right, but not the obligation, to purchase the
stock at a price of $6.0625 per share at any time through July 1, 2000.
On May 24, 1999 we entered into a second agreement whereby the financial
institution acquired 100,000 shares of HSR's common stock from another investor
at a price of $11.9875. We have the right, but not the obligation, to purchase
the stock at a price of $11.9875 per share at any time through January 5, 2001.
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On December 1, 1999 we entered into a third agreement whereby a financial
institution agreed to acquire on the open market up to 300,000 shares of our
stock at the current market price over a three month period beginning December
2, 1999. As of December 31, 1999 the financial institution had acquired 232,400
shares at a weighted average price of $14.37 per share. We have the right, but
not the obligation to purchase the stock at the weighted average price at any
time through September 2, 2001.
If we decide not to purchase the shares on or before the termination of
these agreements, we will receive any increase in the market value of the shares
covered by that agreement above the purchase price of the shares, or will pay
for any loss; however, we may cover losses in most circumstances by issuing
common stock to the financial institution if we choose to do so. All such
amounts will be reflected in stockholders' equity at the time of settlement. We
also pay certain commissions and finance costs. At December 31, 1999 the
aggregate fair market value of HSR's common stock in excess of the underlying
option price attributable to such shares was approximately $9.4 million.
Contingencies. We are currently negotiating with the EPA the resolution of
alleged Clean Water Act Section 404 (wetlands) violations in Louisiana. This
settlement will likely involve the payment of fines and the undertaking of
special environmental projects. As of December 31, 1999 we have accrued an
amount in our financial statements that we believe to be sufficient to cover the
estimated settlement. See Item 3. "Legal Proceedings and Environmental Issues"
and Note 11 of the Notes to Consolidated Financial Statements.
Year 2000. We did not experience any significant malfunctions or errors in
our operating or business systems when the date changed from 1999 to 2000. Based
on operations since January 1, 2000, we do not expect any significant impact to
our ongoing business as a result of the Year 2000 issue. However, it is possible
that the full impact of the date change, which was of concern due to computer
programs that use two digits instead of four digits to define years, has not
been fully recognized. We believe that any such problems are likely to be minor
and correctable. In addition, we could still be negatively impacted if the Year
2000 or similar issues adversely affect our customers or suppliers. We currently
are not aware of any significant Year 2000 or similar problems that have arisen
for our customers and suppliers. As of December 31, 1999, we spent less than
$20,000 on the Year 2000 initiative.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-K includes statements that are not purely historical and are
"forward-looking statements" within the meaning of Section 27A of the Securities
Act and Section 21E of the Securities Exchange Act of 1934, as amended,
including statements regarding our expectations, hopes, beliefs, intentions or
strategies regarding the future. From time to time we also make verbal
forward-looking statements. All statements other than statements of historical
facts included in this Form 10-K or otherwise stated by the Company are
forward-looking statements, including without limitation, statements under Item
3. "Legal Proceedings and Environmental Issues," Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations," and
Item 8. "Financial Statements and Supplementary Data -- Notes to Consolidated
Financial Statements." These statements may concern, among other things:
- reserves, their values and expected growth;
- planned capital expenditures;
- increases in oil and gas production;
- production economics;
- expected drilling opportunities;
- trends or expectations concerning oil and gas prices or market
characteristics;
- marketing, hedging and trading risks, strategies, policies and
procedures;
- our financial position, stability of cash flow, debt service capabilities
and capital availability;
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<PAGE> 30
- the amount of expected Section 29 tax credit payments;
- the ability to manage risk through hedging and similar activities;
- business strategy and other plans and objectives for future operations;
- planned acquisitions;
- potential liabilities or the expected absence thereof; and
- the potential outcome of environmental matters, litigation or other
proceedings.
All forward-looking statements included in this Form 10-K are based on
information available to us on the date hereof or at the time verbal statements
are made, and we assume no obligation to update such forward-looking statements.
Although we believe the forward-looking statements are based on reasonable
assumptions, we can give no assurance that our expectations will prove to have
been correct or that we will take any actions that may presently be planned.
Actual results may differ materially from any forward-looking statements made by
us depending on a variety of factors, including, among others, the factors
discussed in "Certain Considerations."
CERTAIN CONSIDERATIONS
Volatility Of Oil And Gas Prices; Marketability Of Production. Oil and gas
prices can be extremely volatile and have recently increased significantly from
earlier levels. Gas prices affect us more than oil prices, because most of our
production and reserves are gas. At December 31, 1999, approximately 78% of our
estimated reserves were gas and approximately 80% of our total production during
1999 was gas.
Our revenues, profitability and future rate of growth depend substantially
upon prevailing prices for our oil and gas. Prices also affect the amount of
cash flow available for capital expenditures and our ability to borrow money or
raise additional capital.
We cannot predict future oil and gas prices. Factors that cause this
fluctuation include:
- changes in supply and demand;
- the level of consumer product demand;
- market uncertainty;
- weather conditions;
- federal and state regulation of oil and gas production and
transportation;
- the price and availability of alternative fuels;
- political conditions in the Middle East and other international producing
regions;
- the foreign supply of oil and gas;
- the price of oil and gas imports;
- actions of state and local agencies, the United States and foreign
governments and international cartels; and
- general economic conditions throughout the world.
These external factors and the volatile nature of the energy markets make
it impossible to forecast accurately future prices of oil and gas. Prices for
D-J Basin gas, which represents a significant portion of our overall production,
have at times been more volatile than the prices prevailing in the broader
United States gas market, however this has not been the case in recent months.
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Although from time to time we hedge a portion of our oil and gas production
to provide some protection from price fluctuation, any substantial or extended
decline in the price of oil or gas would have a material adverse effect on our
financial condition and results of operations. Hedging arrangements may limit
the risk of declines in pricing, but also may limit further revenues from price
increases.
The marketability of our production depends upon the availability and
capacity of refineries, gas gathering systems, pipelines and processing
facilities. Federal and state regulation of oil and gas production and
transportation, general economic conditions and changes in supply and demand all
could adversely affect our ability to produce and market our oil and gas. If
market factors were to change dramatically, the financial impact on us could be
substantial. The availability of markets and the volatility of product prices
are beyond our control and thus represent a significant risk.
Effects Of Leverage; Existing Indebtedness. As of December 31, 1999, our
total long-term debt was approximately $560.1 million. Our level of debt has
important consequences, including the following:
(i) our ability to obtain additional financing in the future for
working capital, capital expenditures, acquisitions or general corporate
purposes may be impaired;
(ii) a portion of our cash flow from operations must be dedicated to
the payment of the principal of and interest on our existing debt;
(iii) certain of our borrowings, principally those under our revolving
credit facility, are at variable rates of interest, which may make us
vulnerable to increases in interest rates; and
(iv) the terms of certain of our indebtedness permit our creditors to
accelerate payments upon certain events of default or a change of control.
As of December 31, 1999, $97.0 million, or 22.6% of our long-term debt
bears interest at floating rates. This does not include an additional $130.0
million which also bears interest at floating rates, but against which we have
entered into interest rate hedging agreements. Together, without considering the
effect of those interest rate hedging agreements, $227.0 million, or 40.5% of
our long-term debt is characterized by floating rate obligations. Interest rates
on our debt ranged from 6.15% to 9.875% per annum in 1999.
Our Chase revolving credit facility, and the indentures under which our
9 1/4% Senior Subordinated Notes due 2006 and 9 7/8% Senior Subordinated Notes
due 2003 were issued, impose financial and other restrictions on us and our
subsidiaries, including limitations on the incurrence of additional indebtedness
and limitations on the sale of assets. Our Chase facility also requires us to:
(i) make periodic payments of interest;
(ii) make principal payments from the proceeds of certain asset sales
and in the event our outstanding debt exceeds the borrowing base;
(iii) maintain certain financial ratios, including interest coverage
and leverage ratios; and
(iv) maintain a minimum level of consolidated cash flow.
We cannot assure you that these requirements or other material requirements
of our Chase facility will be met in the future. If they are not, the lenders
would be entitled to declare the indebtedness thereunder immediately due and
payable. Additionally, in the event of such an acceleration of indebtedness by
the lenders under our revolving credit facility, a default would be deemed to
occur under the terms of the 9 1/4% Notes and the 9 7/8% Notes. In addition, the
indentures contain certain restrictive covenants that may limit our ability to
engage in certain transactions.
Based upon the current and anticipated level of operations, we believe that
our cash flow from operations, together with the proceeds available under our
Chase facility and other sources of liquidity, will be adequate to meet our
anticipated requirements in the foreseeable future for working capital, capital
expenditures, interest payments and scheduled principal payments. We cannot
assure you, however, that our business will continue to generate cash flow at or
above current levels. If we are unable to generate
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sufficient cash flow from operations to pay our debt, we would be required to
refinance all or a portion of our existing debt (provided the necessary consents
are obtained), or to obtain additional financing, or to sell substantial assets.
There can be no assurance that a refinancing would be possible or that any
additional financing could be obtained. Our ability to pay our debt and reduce
total indebtedness depends not only upon our future drilling and production
performance, but also on oil and gas prices, general economic conditions and
financial, business and other factors affecting our operations, many of which
are beyond our control. Our strategy and historical focus has been, and is
expected to continue to be, the development, acquisition, exploitation,
exploration, production and marketing of oil and gas. Each of these activities
requires substantial capital. We intend to finance such capital expenditures in
the future through cash flow from operations, the incurrence of additional
indebtedness and/or the issuance of additional equity securities.
Estimation Of Reserves. The reserve data in this Form 10-K are calculated
estimates only. There are numerous uncertainties in estimating quantities of
proved reserves, future rates of production and the timing and success of
development expenditures, including many factors beyond our control. Although we
believe that all of our reserve estimates are reasonable, reserve estimates are
only estimates and should be expected to change as additional information
becomes available. Furthermore, estimates of oil and gas reserves, of necessity,
are projections based on engineering, geologic and production data, and the
interpretation thereof, the projection of future rates of production and the
timing and success of development expenditures.
Reserve engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be exactly measured and the accuracy of
any reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. Accordingly, estimates
of the economically recoverable quantities of oil and gas attributable to any
particular property or group of properties, classifications of such reserves
based on risk of recovery and estimates of the future net cash flows expected
therefrom, which are prepared by different engineers or by the same engineers at
different times, may vary substantially. Moreover, we cannot assure you that the
reserves set forth herein will ultimately be produced or that the proved
undeveloped reserves will be developed within the periods anticipated. Variances
from the estimates contained herein could be material. In addition, the
estimates of future net revenues from our proved reserves and the present value
of these reserves are based upon certain assumptions about production levels,
prices and costs, which may be inaccurately estimated. With respect to such
estimates, we emphasize that the discounted future net cash flows should not be
construed as representative of the fair market value of our proved oil and gas
properties, as discounted future net cash flows are based upon projected cash
flows that do not provide for changes in oil and gas prices or for changes in
expenses and capital costs. The accuracy of these estimates is highly dependent
upon the accuracy of the assumptions upon which they were based. Actual results
may differ materially from the results estimated.
Replacement Of Reserves. Our future performance depends in part upon our
ability to acquire, find and develop additional oil and gas reserves that are
economically recoverable. Without successful acquisition, exploration or
development activities, our reserves will decline over time. We cannot assure
you that we will be able to acquire or find and develop additional reserves on
an economic basis.
Our business is capital intensive and, to maintain our asset base of proved
oil and gas reserves, a significant amount of cash flow from operations must be
reinvested in development or exploration activities or property acquisitions. To
the extent cash flow from operations is reduced and external sources of capital
become limited or unavailable, our ability to make the necessary capital
investments to maintain or expand our asset base would be impaired. Without such
investment, our oil and gas reserves will decline over time.
Our strategy will include continued exploitation and exploration of our
existing properties and may include opportunistic acquisitions of other oil and
gas properties. The successful acquisition of producing properties requires an
assessment of recoverable reserves, future oil and gas prices and operating
costs, potential environmental and other liabilities and other factors. These
assessments are necessarily inexact and their accuracy inherently uncertain. We
cannot assure you that our acquisition activities and
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exploration and development projects will result in increases in reserves. Our
operations may be curtailed, delayed or canceled as a result of a lack of
adequate capital and other factors, such as title problems, weather, compliance
with governmental regulations or price controls, mechanical difficulties or
shortages or delays in the delivery of equipment. Furthermore, while our
revenues may increase if prevailing gas and oil prices increase significantly,
our finding costs for additional reserves could also increase. In addition, the
costs of exploration and development may materially exceed initial estimates.
Risks Of Hedging And Trading Transactions. In order to manage our exposure
to price risks in marketing our oil and gas and in connection with our trading
activities, we have in the past entered into and may in the future enter into
oil and gas futures contracts on the New York Mercantile Exchange, fixed price
delivery contracts and financial swaps. Those transactions that are intended to
reduce the effects of volatility of the price of oil and gas may limit our
potential gains if oil and gas prices were to rise substantially over the price
established by the hedge. In addition, our hedging and trading may expose us to
the risk of financial loss in certain circumstances, including instances in
which:
(i) production is less than expected and therefore, is less than our
hedged volumes;
(ii) there is a widening of price differentials between delivery
points for our production and Henry Hub (in the case of NYMEX futures
contracts) or delivery points required by fixed price delivery contracts to
the extent they differ from those of our production;
(iii) our customers or the counterparties to our futures contracts
fail to purchase or deliver the contracted quantities of oil or gas or to
honor their financial commitments;
(iv) a sudden, unexpected event materially affects oil or gas prices;
or
(v) a person connected with our trading activity fraudulently or
otherwise circumvents our controls and causes losses from unauthorized
hedging or trading activity.
Governmental And Environmental Regulation. Our operations are subject to
various federal, state and local governmental laws and regulations, which may be
changed from time to time in response to economic or political factors. Matters
subject to regulation include, but are not limited to, drilling and operations
permits and approvals, performance bonds, reports concerning operations,
discharge and other permitting requirements, the spacing of wells, unitization
and pooling of properties and taxation.
Our operations are also subject to complex and constantly changing
environmental laws and regulations adopted by federal, state and local
governmental authorities. For example, our pipeline operations may be subject to
recently adopted stricter emissions control and monitoring requirements under
The Clean Air Act. Compliance with such laws has not had a material adverse
effect upon HSR to date. Nevertheless, the discharge of oil, gas or other
pollutants into the air, soil or water or impacting wetlands may give rise to
significant liabilities of the Company to the government and/or third parties,
and may require us to incur substantial costs for remediation. Moreover, we have
agreed to indemnify certain sellers of producing properties from whom we have
acquired properties against certain liabilities for environmental claims
associated with the acquired properties. We cannot assure you that existing
environmental laws or regulations, as currently interpreted or as may be in the
future, or future laws or regulations will not materially adversely affect our
results of operations and financial condition or that material indemnity claims
will not arise against us with respect to acquired properties.
Additionally, various cities and counties are currently reviewing their
ordinances to determine the level of regulatory authority, if any, they should
assert over oil and gas operations.
Operating Hazards; Uninsured Risks. Oil and gas drilling and production
activities are subject to numerous risks, many of which are beyond our control.
These risks include the following:
- no commercially productive oil or gas reservoir may be found;
- oil and gas drilling and production activities may be delayed or
canceled;
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- title problems may delay or prohibit drilling, cause a loss of interest
in a well, or cause other problems or losses;
- weather problems may interfere with drilling or production;
- mechanical difficulties or shortages or delays in the delivery of
drilling rigs and other equipment may occur; and
- pipeline and compressor equipment may fail, causing a reduction in or
interruption of deliveries to market and the shutting in of wells.
We cannot assure you that the new wells we drill will be productive or that
we will recover all or any of our investment. Drilling for oil or gas may be
unprofitable. Dry holes and wells that are productive but do not produce
sufficient net revenues after drilling, operating and other costs are
unprofitable. In addition, our properties may be susceptible to oil and gas
drainage from production by other operators on adjacent lands.
Our operations are subject to hazards and risks inherent in drilling for
and production and transportation of oil and gas, such as fires, natural
disasters, explosions, encountering formations with abnormal pressures,
blowouts, cratering, pipeline or compressor failures and spills, any of which
can result in loss of oil and gas, environmental pollution, personal injury
claims and other damage or impacts to our properties and others, including
suspension of operations. The business is also subject to environmental hazards
such as oil spills, gas leaks, ruptures and discharges of toxic gases, which
could expose us to substantial liability due to pollution and other
environmental damage. Our insurance coverages include, but are not limited to,
comprehensive general liability, automobile, personal injury, bodily injury and
property damage, pollution liability, physical damage on certain assets,
workers' compensation and control of well insurance. We believe that our
insurance is adequate and customary for companies of a similar size engaged in
operations similar to ours, but losses could occur for uninsurable or uninsured
risks or in amounts in excess of existing insurance coverage.
Competition. The oil and gas industry is highly competitive. We compete in
the areas of property acquisitions and the exploration, exploitation,
development, production and marketing of oil and gas with major oil companies,
other independent oil and gas concerns and individual producers and operators.
We also compete with these companies in recruiting and retaining qualified
employees. Many of these competitors have financial and other resources
substantially greater than ours.
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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. Council of Petroleum Accountants Societies.
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.
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.
Hydraulic fracturing (or "frac"). A mechanical technique used to enhance
productivity and ultimate reserve recovery. Fluids and a proppant are forced
into a particular reservoir at flow rates and pressure sufficient to create a
series of fractures or cracks in that reservoir. The fluids are removed leaving
the proppant in place.
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
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geological studies which demonstrate that the existing well density does not
adequately drain the reservoir.
Lease operating expense or LOE. All direct costs associated with and
necessary to operate a producing property.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MBoe. One thousand barrels of oil equivalent.
MBtu. One thousand Btu.
Mcf. One thousand cubic feet of gas.
Mcfe. One thousand cubic feet of gas equivalent, determined using the ratio
of one Bbl of crude oil equals six Mcfe (including natural gas liquids).
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
MMBoe. One million barrels of oil equivalent.
MMBtu. One million Btu.
MMcf. One million cubic feet of gas.
MMcfe. One million cubic feet of gas equivalent.
Multi-pay horizons. A wellbore with more than one zone that may potentially
produce hydrocarbons.
Net acres or net wells. The sum of the working interests owned in gross
acres or gross wells.
Net cash flow. Net cash flow is defined as net income plus geological and
geophysical costs, exploratory and abandonment costs, depletion, depreciation
and amortization, impairment and gain/loss on sale, income taxes and
extraordinary items.
Present value of estimated future net revenues, pretax present value at
constant prices of estimated future net revenues. Estimated future net revenues
before income taxes, discounted using a factor of ten percent per annum and with
no price or cost escalation or de-escalation in accordance with guidelines
promulgated by the Securities and Exchange Commission.
Productive well. A well that is producing or that is capable of producing
oil or gas.
Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, gas and natural gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
Proved undeveloped location. A site on which a development well can be
drilled consistent with local spacing rules for the purpose of recovering proved
reserves.
Proved undeveloped reserves. Reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required to establish production.
Recompletions. Within an existing wellbore, a recompletion involves
completion for production of a formation other than those which have previously
been productive. It is the mechanism by which behind-pipe reserves become
productive.
Refrac. Within an existing wellbore, a refrac involves a new hydraulic
fracture stimulation of a currently or previously producing formation.
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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.
3-D seismic projects. 3-D seismic projects involve the use of seismic
reflections in three dimensions to assist in mapping the structural and
stratigraphic aspects of certain reservoirs lending themselves to the
application of this advanced technology. Particularly when coupled with advanced
processing, interpretation, geostatistical techniques and interpretive geology,
this technology can materially reduce the risk associated with some types of
drilling.
Undeveloped acres. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.
Wattenberg. The geographic region in the D-J Basin located approximately 35
miles north 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.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of HS Resources, Inc.:
We have audited the accompanying consolidated balance sheets of HS
Resources, Inc. (a Delaware corporation) and subsidiaries as of December 31,
1999 and 1998, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1999. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of HS Resources, Inc. and
subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.
As discussed in Note 1 to the consolidated financial statements, in 1998
the Company retroactively adopted the successful efforts method of accounting
for its oil and gas producing activities.
ARTHUR ANDERSEN LLP
Denver, Colorado
February 11, 2000
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HS RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1999 1998
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Current Assets
Cash and cash equivalents................................. $ 518 $ 9,658
Margin deposits........................................... 935 622
Accounts receivable
Oil and gas sales...................................... 31,602 20,528
Trading and transportation............................. 18,518 14,012
Trade.................................................. 3,089 4,080
Other.................................................. 16,211 8,277
Lease and well equipment inventory, at cost............... 1,249 710
Prepaid expenses and other................................ 3,966 2,378
Notes receivable from officers for exercise of stock
options................................................ 1,574 --
--------- ---------
Total current assets.............................. 77,662 60,265
--------- ---------
Oil and Gas Properties, at cost, using the successful
efforts method
Undeveloped acreage....................................... 99,358 108,030
Costs subject to depreciation, depletion and
amortization........................................... 892,976 816,633
Less accumulated depreciation, depletion and
amortization........................................... (227,691) (175,729)
--------- ---------
Net oil and gas properties........................ 764,643 748,934
--------- ---------
Gas Gathering and Transportation Facilities, at cost, net of
accumulated depreciation of $2,016 and $1,617 at December
31, 1999 and 1998, respectively........................... 52,611 4,274
--------- ---------
Other Assets
Workover rigs and equipment, net.......................... 832 --
Deferred charges and other, net........................... 10,070 11,002
Office and transportation equipment and other property,
net of accumulated depreciation of $6,509 and $5,883 at
December 31, 1999 and 1998, respectively............... 2,208 3,018
Notes receivable from officers for exercise of stock
options and issuance of common stock (Note 8).......... 812 2,246
Goodwill, net of accumulated amortization of $1,260 and
$900 at December 31, 1999 and 1998, respectively (Note
2)..................................................... 2,340 2,700
--------- ---------
Total other assets................................ 16,262 18,966
--------- ---------
Total Assets...................................... $ 911,178 $ 832,439
========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
40
<PAGE> 41
HS RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1999 1998
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Current Liabilities
Accounts payable
Trade.................................................. $ 26,653 $ 21,409
Revenue................................................ 36,897 20,915
Gas purchases.......................................... 9,290 7,238
Accrued expenses
Ad valorem and production taxes........................ 10,624 12,027
Interest............................................... 5,233 6,665
Other.................................................. 5,389 7,382
Income taxes payable...................................... 958 2,793
Oil and gas production note payable....................... -- 735
Payable to KMI............................................ 19,551 --
-------- --------
Total current liabilities......................... 114,595 79,164
-------- --------
Accrued Ad Valorem Taxes.................................... 15,804 12,451
-------- --------
Deferred Revenue (Note 12).................................. -- 8,908
-------- --------
Payable to KMI.............................................. 27,556 --
-------- --------
Long-Term Bank Debt......................................... 227,000 230,000
-------- --------
9 7/8% Senior Subordinated Notes, due 2003, net of
unamortized discount of $229 and $288 at December 31, 1999
and 1998, respectively.................................... 74,771 74,712
-------- --------
9 1/4% Series A Senior Subordinated Notes, due 2006, net of
unamortized discount of $534 and $612 at December 31, 1999
and 1998, respectively.................................... 149,466 149,388
-------- --------
9 1/4% Series B Senior Subordinated Notes, due 2006, net of
unamortized discount of $3,653 and $4,184 at December 31,
1999 and 1998, respectively............................... 81,347 80,816
-------- --------
Deferred Income Taxes....................................... 53,246 44,138
-------- --------
Commitments and Contingencies (Note 11)
-------- --------
Stockholders' Equity (Note 7)
Preferred stock........................................... -- --
Common stock, $.001 par value, 50,000 shares authorized;
19,528 and 19,127 shares issued and outstanding at
December 31, 1999 and 1998, respectively............... 20 19
Additional paid-in capital................................ 191,406 188,196
Retained deficit.......................................... (14,302) (25,988)
Deferred compensation..................................... (1,981) (1,749)
Treasury stock, at cost, 731 and 801 shares at December
31, 1999 and 1998, respectively........................ (7,750) (7,616)
-------- --------
Total stockholders' equity........................ 167,393 152,862
-------- --------
Total Liabilities and Stockholders' Equity........ $911,178 $832,439
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
41
<PAGE> 42
HS RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
Revenues
Oil and gas sales....................................... $164,660 $150,087 $137,251
Trading and transportation.............................. 52,662 54,144 90,062
Other gas revenues...................................... 10,132 8,560 4,449
Gathering and transmission system revenues.............. 1,286 -- --
Interest income and other............................... 610 1,405 1,943
-------- -------- --------
Total revenues.................................. 229,350 214,196 233,705
-------- -------- --------
Expenses
Production taxes........................................ 10,309 10,422 9,703
Lease operating......................................... 28,014 30,410 24,848
Cost of trading and transportation...................... 49,567 50,451 88,402
Gathering and transmission system operating expenses.... 386 -- --
Depreciation, depletion and amortization................ 54,400 61,223 45,757
Exploratory and abandonment............................. 13,525 15,420 13,438
Geological and geophysical.............................. 6,837 14,308 17,049
Impairment and (gain)/loss on sales of oil and gas
properties........................................... (1,171) 11,986 15,710
General and administrative.............................. 5,823 8,061 11,550
Interest................................................ 42,781 41,990 32,297
-------- -------- --------
Total expenses.................................. 210,471 244,271 258,754
-------- -------- --------
Income (loss) before provision (benefit) for income
taxes................................................... 18,879 (30,075) (25,049)
Provision (benefit) for income taxes...................... 7,193 (11,459) (9,544)
-------- -------- --------
Net income (loss)......................................... $ 11,686 $(18,616) $(15,505)
======== ======== ========
Basic earnings (loss) per share........................... $ 0.63 $ (1.00) $ (0.91)
======== ======== ========
Diluted earnings (loss) per share......................... $ 0.62 $ (1.00) $ (0.91)
======== ======== ========
Weighted average number of common shares outstanding...... 18,697 18,609 17,119
======== ======== ========
Weighted average number of common shares outstanding
assuming dilution....................................... 18,888 18,609 17,119
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
42
<PAGE> 43
HS RESOURCES, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998, AND 1997
<TABLE>
<CAPTION>
COMMON STOCK ADDITIONAL RETAINED TREASURY STOCK
--------------- PAID-IN EARNINGS DEFERRED ----------------
SHARES AMOUNT CAPITAL (DEFICIT) COMPENSATION SHARES AMOUNT
------ ------ ---------- --------- ------------ ------ -------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1996........ 17,128 $17 $163,115 $ 8,133 $ (171) (122) $(1,670)
Purchase of treasury stock...... -- -- -- -- -- (101) (1,399)
Transfer of treasury stock to
401(k) Plan................... -- -- (68) -- -- 36 485
Issuance of common stock for
Amoco Acquisition............. 1,200 1 19,999 -- -- -- --
Issuance of treasury stock for
exercise of options including
income tax benefit............ -- -- (34) -- -- 27 367
Issuance of restricted stock.... 3 -- 45 -- (45) -- --
Amortization of deferred
compensation.................. -- -- -- -- 72 -- --
Issuance of common stock........ 12 -- 135 -- -- -- --
Exercise of warrants and
options....................... 312 1 (1) -- -- -- --
Net loss........................ -- -- -- (15,505) -- -- --
------ --- -------- -------- ------- ---- -------
BALANCE, DECEMBER 31, 1997........ 18,655 19 183,191 (7,372) (144) (160) (2,217)
====== === ======== ======== ======= ==== =======
Purchase of treasury stock...... -- -- -- -- -- (722) (6,524)
Transfer of treasury stock to
401(k) Plan................... -- -- 7 -- -- 39 542
Issuance of treasury stock for
exercise of options including
income tax benefit............ -- -- (115) -- -- 42 583
Issuance of restricted stock.... 32 -- 428 -- (428) -- --
Amortization of deferred
compensation.................. -- -- -- -- 307 -- --
Issuance of performance
shares........................ 106 -- 1,534 -- (1,534) -- --
Exercise of stock options,
including income tax
benefit....................... 337 -- 3,201 -- -- -- --
Restricted stock forfeited...... (3) -- (50) -- 50 -- --
Net loss........................ -- -- -- (18,616) -- -- --
------ --- -------- -------- ------- ---- -------
BALANCE, DECEMBER 31, 1998........ 19,127 19 188,196 (25,988) (1,749) (801) (7,616)
====== === ======== ======== ======= ==== =======
Purchase of treasury stock...... -- -- -- -- -- (128) (2,055)
Transfer of treasury stock to
401(k) Plan................... -- -- 50 -- -- 75 712
Issuance of treasury stock for
exercise of options including
income tax benefit............ -- -- 492 -- -- 123 1,209
Issuance of restricted stock.... 34 -- 301 -- (301) -- --
Amortization of deferred
compensation.................. -- -- -- -- 1,067 -- --
Issuance of performance
shares........................ 132 1 997 -- (998) -- --
Issuance of common stock........ 235 -- 1,370 -- -- -- --
Net income...................... -- -- -- 11,686 -- -- --
------ --- -------- -------- ------- ---- -------
BALANCE, DECEMBER 31, 1999........ 19,528 $20 $191,406 $(14,302) $(1,981) (731) $(7,750)
====== === ======== ======== ======= ==== =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
43
<PAGE> 44
HS RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
-------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)......................................... $ 11,686 $ (18,616) $(15,505)
Adjustments to reconcile net income to net cash provided
by operating activities
Depreciation, depletion and amortization................ 54,400 61,223 45,757
Impairment and (gain)/loss on sales of oil and gas
properties............................................ (1,171) 11,986 15,710
Amortization of deferred charges, debt issue costs and
deferred compensation................................. 4,210 2,621 1,830
Surrendered and expired acreage......................... 5,211 10,422 6,195
Transfer of treasury stock to 401(k) Plan............... 763 549 417
Gain on sale of fixed assets............................ -- (235) --
Deferred income tax provision (benefit)................. 7,008 (14,106) (10,554)
(Increase) decrease in accounts and notes receivable.... (22,523) (1,186) 2,558
Increase in accounts payable and accrued expenses....... 18,524 10,069 7,947
(Decease) increase in deferred revenue, net............. (8,908) (965) 9,873
Other................................................... (4,189) (1,257) 843
-------- --------- --------
Net cash provided by operating activities.......... 65,011 60,505 65,071
-------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration, development and leasehold costs.............. (75,209) (98,307) (46,189)
Purchase of unproved and proved properties................ -- (4,754) (299,087)
Purchase of workover rigs and equipment................... (875) -- --
Gas gathering and transportation facilities additions..... (1,629) (28) (157)
Other property additions.................................. (353) (859) (1,712)
Proceeds from the sale of oil and gas properties.......... 3,026 151,031 35,603
Proceeds from the sale of fixed assets and other
property................................................ -- 1,234 --
Increase in property related payables..................... 2,809 3,694 11,272
-------- --------- --------
Net cash (used in) provided by investing
activities....................................... (72,231) 52,011 (300,270)
-------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from debt........................................ 81,000 154,750 337,000
Repayments of debt........................................ (84,000) (256,000) (99,000)
Debt issuance costs....................................... -- (2,460) (2,948)
Issuance of common stock.................................. 611 -- 135
Exercise of options....................................... 1,701 468 333
Purchase of treasury stock................................ (2,055) (6,524) (1,399)
Payment of officer note and interest...................... 823 -- --
Minority interest, net.................................... -- -- (779)
-------- --------- --------
Net cash (used in) provided by financing
activities....................................... (1,920) (109,766) 233,342
-------- --------- --------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS........ (9,140) 2,750 (1,857)
Cash and cash equivalents, beginning of year.............. 9,658 6,908 8,765
-------- --------- --------
Cash and cash equivalents, end of year.................... $ 518 $ 9,658 $ 6,908
======== ========= ========
SUPPLEMENTAL CASH FLOW DISCLOSURE
Interest paid, net of capitalized interest................ $ 40,542 $ 36,481 $ 28,731
Cash paid for income taxes, net of reimbursements......... $ (68) $ 3,135 $ (413)
Schedule of noncash investing and financing activities:
Exchange of properties in Amoco Acquisition............. $ -- $ -- $ 23,000
Common stock issued in Amoco Acquisition................ $ -- $ -- $ 20,000
Purchase of Wattenberg Gathering System................. $ 47,107 $ -- $ --
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
44
<PAGE> 45
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- THE COMPANY
HS Resources, Inc. (the "Company"), a Delaware corporation, was organized
in January 1987. The Company, directly or through subsidiaries, acquires,
develops, explores for, exploits and produces oil and gas properties. The
Company's primary properties are located in the Denver-Julesburg ("D-J") Basin,
the onshore area of the Texas-Louisiana Gulf Coast and to a lesser extent the
Northern Rocky Mountains. Through its wholly-owned subsidiary, HS Gathering
L.L.C., the Company gathers and transports its own and third party gas. Through
its subsidiary, HS Energy Services, Inc. ("HSES"), the Company markets its own
gas production, markets gas owned by third parties and actively trades both
physical and financial positions in the gas commodities market.
During the fourth quarter of 1998, the Company elected to change its
accounting method for oil and gas properties from the full cost method to the
successful efforts method. As required by generally accepted accounting
principles, all financial statements presented as of 1998 were retroactively
restated to give effect to this change in accounting method. The cumulative
effect of this change, net of income taxes, was to reduce December 31, 1997,
retained earnings by $50.1 million. For the statement of operations for the year
ended December 31, 1997, the effect of the accounting change was to decrease net
income by $26.8 million ($1.57 per diluted share).
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company utilizes the successful efforts method of accounting for its
oil and gas properties. Consequently, leasehold costs are capitalized when
incurred. Unproved properties are assessed periodically within specific
geographic areas, and impairments in value are charged to expense. Exploratory
costs, geological and geophysical expenses and delay rentals are charged to
expense as incurred. Exploratory drilling costs are initially capitalized, but
charged to expense if and when the well is determined to be unsuccessful. Costs
of developmental dry holes and proved leaseholds are amortized on the
unit-of-production method based on proved reserves on a field by field basis.
The depreciation of capitalized drilling costs is based on the
unit-of-production method using proved developed reserves on a field by field
basis.
The Company follows Statement of Financial Accounting Standards No. 121
("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of." SFAS 121 requires the Company to assess
the need for an impairment of capitalized costs of oil and gas properties and
other assets. Oil and gas properties are generally assessed on a
property-by-property basis. If an impairment is indicated based on undiscounted
expected future net cash flows, it is recognized to the extent that net
capitalized costs exceed discounted expected future net cash flows. During 1999
no impairments were provided for whereas in 1998 and 1997, the Company recorded
$5.3 million and $1.6 million, respectively, for such impairments. During 1999,
1998 and 1997 the Company capitalized $7.1 million, $11.7 million and $3.8
million, respectively, of interest relating to undeveloped acreage.
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 basis of assets and liabilities for financial reporting and tax reporting
purposes. Such differences relate mainly to depreciable and depletable
properties and intangible drilling costs.
Cash Equivalents. Cash and cash equivalents include cash on hand, amounts
held in banks and highly liquid investments purchased with an original maturity
of three months or less.
45
<PAGE> 46
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Margin Deposits. The Company uses energy related financial instruments to
reduce its exposure to price risk related to natural gas. Margin deposits
consist of monies on deposit with brokers that are restricted to meet exchange
trading requirements (see Note 5).
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. In the event energy
related financial instruments are terminated prior to the period of physical
delivery of the items being hedged, the gains or losses on the energy related
financial instruments at the time of the termination remain deferred until the
period of physical delivery unless both the energy related financial instruments
and the items being hedged result in a loss. If this occurs, the loss is
recorded immediately.
Earnings Per Share. SFAS No. 128, "Earnings Per Share" provides
computation, presentation and disclosure requirements for earnings per share
("EPS"). In the fiscal year ended December 31, 1999, the dilutive impact was
191,000 shares. There was no dilutive impact to weighted average shares for the
fiscal years ended December 31, 1998 and 1997.
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.
Goodwill. In connection with the 1996 merger with Tide West Oil Company,
the Company recorded goodwill of $3.6 million attributable to its trading and
marketing subsidiary, HSES. Such amount is amortized on a straight-line basis
over 10 years.
Gas Imbalances. Gas imbalances are accounted for under the sales method
whereby revenues are recognized based on actual production sold. At December 31,
1999, the Company's gas balancing position was approximately 94,000 Mcf
underproduced.
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 1998, the Financial Accounting Standards
Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133"). This statement was recently amended by SFAS No. 137
extending the adoption period to fiscal years beginning after June 15,
46
<PAGE> 47
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2000. This statement establishes accounting and reporting standards requiring
that every derivative instrument (including certain derivative instruments
embedded in other contracts) be recorded in the balance sheet as either an asset
or liability measured at its fair value. The statement requires that changes in
the derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the statement of operations, and requires that a company must formally
document, designate and assess the effectiveness of transactions that receive
hedge accounting.
The Company has not yet quantified the impact of adopting SFAS 133 on its
financial statements and has not determined the timing of or method of adoption.
However, SFAS 133 could increase volatility in earnings and other comprehensive
income.
In December 1998, the Emerging Issues Task Force reached consensus on Issue
No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" ("EITF Issue 98-10"). EITF Issue 98-10 is effective for
fiscal years beginning after December 15, 1998. EITF Issue 98-10 requires energy
trading contracts to be recorded at fair value on the balance sheet, with the
changes in fair value included in earnings. In accordance with EITF Issue 98-10,
the Company records energy trading contracts at fair value on the balance sheet,
with the changes in fair value included in earnings.
NOTE 3 -- ACQUISITIONS AND DIVESTITURES
Acquisition Of Gas Gathering And Transmission Assets. On November 26, 1999,
the Company acquired certain gas gathering and transmission assets (the
"Wattenberg Gathering System") from Kinder Morgan, Inc. and affiliated entities
("KMI") for an adjusted purchase price of approximately $48 million plus the
future assumption of an operating lease which had a present value of $19
million.
The Wattenberg Gathering System consists of a low pressure gathering system
and a high pressure transmission system. The low pressure gathering system
consists of more than 1,500 miles of pipeline and 3,000 horsepower of
compression, located in five northeastern Colorado counties. Gas is delivered to
the inlet of the high pressure transmission system, which consists of almost 60
miles of high pressure pipeline and almost 40,000 horsepower of compression. The
acquisition is being accounted for using the purchase method of accounting.
Along with the system, the Company acquired a 6.9% interest in the BP Amoco
Wattenberg Gas Processing Plant, and a right of first refusal to purchase the
remaining interest in the plant.
Sale Of HSRTW, Inc. On July 28, 1998, the Company announced the sale of its
Mid-Continent oil and gas subsidiary, HSRTW, Inc., to Universal Resources Corp.,
a subsidiary of Questar Corp., for $157.5 million in cash (the "Mid-Continent
Sale"). HSRTW, Inc. owned interests in approximately 1,000 wells located in the
Anadarko and Arkoma basins of Oklahoma and in Texas, with approximately 32 MMBoe
of proved reserves as of year-end 1997. The transaction closed and was effective
on September 1, 1998, with net proceeds applied to the repayment of bank debt.
The Company retained its ownership of HSES, its Tulsa-based gas trading and
marketing subsidiary.
Amoco Acquisition. Effective December 1, 1997, the Company acquired from
Amoco Production Company ("Amoco") all of Amoco's producing and non-producing
oil and gas properties in the Wattenberg field area of the D-J Basin (the "Amoco
Acquisition") for $290 million in cash, 1.2 million 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 contained
estimated proved reserves of 70.2 MMBoe at December 31, 1997 and included
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.
47
<PAGE> 48
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 4 -- PRO FORMA STATEMENT (UNAUDITED)
The following table sets forth the condensed unaudited pro forma operating
results of the Company for the twelve months ended December 31, 1999. The
condensed pro forma operating results assume that the acquisition of the gas
gathering and transmission assets from KMI had occurred on January 1, 1999 (see
Note 3). The condensed pro forma results are not necessarily indicative of the
results of operations had the acquisition been consummated on January 1, 1999,
and may not necessarily be indicative of future performance.
<TABLE>
<CAPTION>
TWELVE MONTHS
ENDED DECEMBER 31,
1999
IN THOUSANDS, EXCEPT PER SHARE AMOUNTS (UNAUDITED)
- - -------------------------------------- ------------------
<S> <C>
Revenues........................................... $247,948
Net income......................................... $ 17,815
Diluted income per share........................... $ 0.94
Weighted average number of common
shares outstanding assuming dilution............. 18,888
</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. 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 require 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). Hedging contracts for Company owned production reduced
the Company's oil and gas sales by $6.1 million in 1999 and by $2.9 million in
1997 and increased the Company's oil and gas sales by $9.0 million in 1998.
Hedging contracts for third party gas increased trading and transportation
revenues by approximately $36,000, $346,000 and $1.2 million in 1999, 1998 and
1997, respectively.
48
<PAGE> 49
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As a part of its risk management program, the Company generally enters into
hedges for delivery into one of several pipelines located near its producing
regions, Panhandle Eastern Pipeline Company ("PEPL"), Northwest Pipeline
Corporation ("NW"), Colorado Interstate Gas Company ("CIG"), or at the New York
Mercantile Exchange ("NYMEX") prices settled at the Henry Hub. With respect to
the NYMEX hedged volumes that exceed the Company's Gulf Coast volumes, the
Company usually hedges basis to its producing regions. As of December 31, 1999,
the Company held hedge swap positions as follows:
GAS HEDGES
<TABLE>
<CAPTION>
AVERAGE DAILY FAIR VALUE AT
QUANTITY SETTLEMENT PRICE DECEMBER 31, 1999
TIME PERIOD (MMBTU) LOCATION (PER MMBTU) GAIN (LOSS)
- - ----------- ------------- ---------- ----------- -----------------
<S> <C> <C> <C> <C>
January 2000-March 2000.................. 10,000 PEPL $2.490 $233,375
January 2000-March 2000.................. 5,000 PEPL $2.520 $130,338
January 2000-March 2000.................. 20,000 PEPL $2.700 $848,950
January 2000-March 2000.................. 10,000 NW $2.175 $(15,175)
April 2000-October 2000.................. 15,000 NW $2.200 $426,177
April 2000-October 2000.................. 5,000 NW $2.200 $142,059
April 2000-October 2000.................. 10,000 NW $2.250 $391,118
January 2000-January 2000................ 25,000 NYMEX $2.405 $ 47,275
January 2000-January 2000................ 15,000 NYMEX $2.250 $ 17,903
February 2000-February 2000.............. 15,000 NYMEX $2.360 $ 13,485
February 2000-February 2000.............. 25,000 NYMEX $2.205 $ 4,350
March 2000-March 2000.................... 15,000 NYMEX $2.400 $ 37,200
March 2000-March 2000.................... 25,000 NYMEX $2.245 $ 62,000
January 2000-February 2000............... 20,000 NYMEX $2.435 $117,900
March 2000-March 2000.................... 20,000 NYMEX $2.465 $ 89,900
April 2000-October 2000.................. 10,000 NYMEX $2.198 $278,768
April 2000-October 2000.................. 25,000 NYMEX $2.150 $442,795
April 2000-October 2000.................. 10,000 NYMEX $2.115 $102,218
April 2000-October 2000.................. 30,000 NYMEX $2.052 $(94,596)
November 2000-March 2001................. 20,000 NYMEX $2.195 $203,240
April 2001-October 2001.................. 10,000 NYMEX $2.090 $ 55,540
April 2001-October 2001.................. 20,000 NYMEX $2.110 $196,680
</TABLE>
WRITTEN GAS CALLS
<TABLE>
<CAPTION>
AVERAGE DAILY FAIR VALUE AT
QUANTITY SETTLEMENT PRICE DECEMBER 31, 1999
TIME PERIOD (MMBTU) LOCATION (PER MMBTU) GAIN (LOSS)
- - ----------- ------------- ---------- ----------- -----------------
<S> <C> <C> <C> <C>
January 2000-December 2000............... 20,000 NYMEX $3.100 $(338,066)
January 2001-December 2001............... 20,000 NYMEX $3.000 $(752,538)
</TABLE>
49
<PAGE> 50
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 1999 the Company has hedged its expected oil production
as follows:
CRUDE HEDGES
<TABLE>
<CAPTION>
AVERAGE MONTHLY FAIR VALUE AT
QUANTITY SETTLEMENT PRICE DECEMBER 31, 1999
TIME PERIOD (BBL) LOCATION (PER BBL) GAIN (LOSS)
- - ----------- --------------- ---------- --------- -----------------
<S> <C> <C> <C> <C>
January 2000-March 2000.................. 30,333 WTI $13.300 $(1,023,790)
January 2000-March 2000.................. 151,667 WTI $23.950 $ (273,198)
April 2000-June 2000..................... 61,333 WTI $22.600 $ 33,643
</TABLE>
WRITTEN CRUDE CALLS
<TABLE>
<CAPTION>
AVERAGE MONTHLY FAIR VALUE AT
QUANTITY SETTLEMENT PRICE DECEMBER 31, 1999
TIME PERIOD (BBL) LOCATION (PER BBL) GAIN (LOSS)
- - ----------- --------------- ---------- --------- -----------------
<S> <C> <C> <C> <C>
January 2000-December 2000............... 61,000 WTI $21.400 $(1,703,129)
January 2001-December 2001............... 60,833 WTI $20.400 $(1,141,401)
</TABLE>
Additionally, with respect to the hedging of third party gas, the Company
has hedged 3.3 Bcf from January 2000 through December 2000 with offsetting
physical positions at settlement prices which are based upon NYMEX future prices
or other published indices. The fair market value of these hedges at December
31, 1999 was a gain of $95,026.
The Company routinely buys and sells options or forward contracts as part
of its overall hedging strategy. As of December 31, 1999, the Company had
written natural gas and crude calls through December 2001. These calls are
hedged by future production. The counterparties to these call transactions
require the maintenance of specified margin balances. Fluctuations in the
mark-to-market value of these instruments could result in additional margin
requirements over the term of the underlying contracts.
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 "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.
The Company's 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. For the
years ended December 31, 1999, 1998 and 1997, net gains of $3.3 million, $2.8
million and $0.5 million, respectively, were recognized in connection with
financial trading activities and are included in "trading and transportation
revenues."
Credit Risk. While notional amounts are used to express the volume of
various derivative financial instruments, the amounts potentially subject to
credit risk in the event of nonperformance by the third parties are
substantially smaller. Counterparties to the swap, collar, floor and ceiling
arrangements discussed above are generally investment grade institutions.
Accordingly, the Company does not anticipate any material impact to the
Company's 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.
50
<PAGE> 51
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 6 -- LONG-TERM DEBT
Long-term Bank And Other Debt. Debt at December 31, 1999 and 1998 consists
of the following (in thousands):
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
Bank debt................................................... $227,000 $230,000
Payable to KMI.............................................. 47,107 --
Other debt.................................................. -- 735
-------- --------
274,107 230,735
Less -- current portion..................................... (19,551) (735)
-------- --------
Long-term bank debt and other debt, net of current
portion................................................... $254,556 $230,000
======== ========
9 7/8% Senior Subordinated notes due 2003, net of
unamortized discount of $229 and $288 at December 31, 1999
and 1998, respectively.................................... $ 74,771 $ 74,712
======== ========
9 1/4% Series A Senior Subordinated notes due 2006, net of
unamortized discount of $534 and $612 at December 31,
1999, and 1998, respectively.............................. $149,466 $149,388
======== ========
9 1/4% Series B Senior Subordinated notes, due 2006, net of
unamortized discount of $3,653 and $4,184 at December 31,
1999 and 1998, respectively............................... $ 81,347 $ 80,816
======== ========
</TABLE>
Bank Debt. On June 7, 1996, the Company entered into a revolving senior
term credit facility with The Chase Manhattan Bank, as Agent (the "Chase
Facility") which has been subsequently amended. On December 10, 1998, as a
result of the issuance of the Series B 9 1/4% Notes, the Chase Facility was
amended to adjust the borrowing base to $280 million and reflect other changes
required by the issuance of the Notes. The interest rates payable thereunder is
The Chase Manhattan Bank Base Rate plus 0% to 0.625% or LIBOR plus 0.75% to
1.625%. Under the terms of the Chase Facility, no principal payments are
required until December 15, 2002, assuming 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. In March
1999, but effective December 31, 1998, the Company entered into the seventh
amendment to the Chase Facility to modify certain covenants under the facility
as a result of the Company's conversion to the successful efforts method of
accounting. Certain definitions and covenants were revised to make them
consistent with this method of accounting.
Payable To KMI. Payments to KMI are specified in an operating services
agreement, with certain contractual obligations between the Company and KMI. As
specified in the agreement actual payment amounts will be made monthly through
December 2001 with amounts varying depending upon system throughput. The
obligation to KMI represents the present value of contractually defined net
payments based on an assumed volume of throughput discounted at an imputed
interest rate of approximately 11.8%.
Interest Rate Swaps. In the first quarter of 1999, the Company entered into
an interest rate exchange agreement with a financial institution to hedge $50
million of its borrowings at 5.66% through March 31, 2004. During the fourth
quarter of 1998, the Company entered into an interest rate exchange agreement
with a financial institution to hedge its interest rate on $80 million of the
Company's borrowings at 5.86% through December 15, 2006. Under the terms of the
agreements, the difference between the Company's fixed rate and the one-month
LIBOR rate is received or paid by the Company. As part of the $80 million
hedging agreement, the Company's pre-1999 hedging agreements were either
cancelled or offset. Market risk related to borrowings from a one percent change
in interest rates would result in an approximate
51
<PAGE> 52
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$1.0 million annual impact on pre-tax income based on the quarter end borrowing
level and the amount of such borrowings which are not subject to interest rate
swaps.
Senior Subordinated Notes. In December 1998, the Company issued $85 million
of its 9 1/4% Series B senior subordinated notes due in 2006. The notes pay
interest semi-annually on May 15 and November 15. The notes were priced to yield
10.18% and the Company received net proceeds of $78.3 million after discounts,
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, 1999 and 1998, the carrying amount of the
Company's 9 7/8% senior subordinated notes was $74.8 million and $74.7 million
and the estimated fair value was $74.8 million and $73.9 million, respectively.
At December 31, 1999 and 1998, the carrying amount of the 9 1/4% Series A senior
subordinated notes was $149.5 million and $149.4 million and the estimated fair
value was $148.5 million and $144.0 million, respectively. At December 31, 1999
and 1998, the carrying amount of the 9 1/4% Series B senior subordinated notes
was $81.3 million and $80.8 million and the estimated fair value was $84.0
million and $81.6 million. The fair value is estimated based on the quoted
market prices for the same or similar issues, or on the current rates offered to
the Company for debt of the same remaining maturity.
Based on borrowing rates available for bank loans with similar collateral,
the fair value of the borrowing under the bank debt at December 31, 1999, is
estimated to be its carrying value of $227.0 million.
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.
NOTE 7 -- STOCKHOLDERS' EQUITY
Outstanding Shares. In May 1998, the Company's stockholders approved an
increase in the number of authorized shares of the Company's common stock, from
30 million to 50 million.
Series A Convertible Participating Preferred Stock. The Company has
authorized 15 million shares of $.001 par value Series A convertible preferred
stock, of which no shares are currently issued or outstanding. The stock has a
stated value of $13.50 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").
Terms of the Rights Plan provide for a dividend distribution of one right
for each share of HS Resources, Inc. common stock to holders of record at the
close of business on March 14, 1996. The Rights will automatically become part
of and traded with existing and future shares of the Company's common stock. The
Rights will become exercisable only in the event, with certain exceptions, an
acquiring party accumulates 15% or more of HS Resources, Inc.'s voting stock, or
if a party announces an offer to acquire 30% or more of 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% or more of the Company's common stock, or in the event of a merger or
other business combination, each right will entitle
52
<PAGE> 53
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the holder other than the acquiring party to purchase either Company stock or
shares in an "acquiring entity" at a 50% 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% 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, 1999, 1998 and 1997.
Restricted Stock. In 1999, 1998 and 1997 the Company issued 33,984, 32,126
and 2,500 shares of restricted stock and recorded approximately $301,000,
$428,000 and $45,000 of deferred compensation, respectively. The amounts
recorded as deferred compensation represent the difference between the deemed
fair value for accounting purposes and the stock price as determined by the
Company at the date of grant. Such amounts are presented as a reduction of
stockholders' equity and will be amortized over the vesting period of the
related stock. In 1999, 1998 and 1997 the Company amortized approximately
$220,000, $136,000 and $72,000, respectively.
Issuance Of Performance Shares. In May 1998, the Company's stockholders
approved amendments to the Amended and Restated 1997 Performance and Equity
Incentive Plan (the "Plan"). The Plan allows for the issuance of performance
shares to employees, officers and directors. Accelerated vesting of such shares
is dependent on the attainment by the Company of defined performance goals.
These shares have a base vesting schedule over nine years with accelerated
vesting to occur no earlier than one-fourth of the shares in each of the first
four years. In 1998, the Company issued 106,234 performance shares. In
connection with this issuance, the Company recorded deferred compensation of
$1.5 million which is being amortized based on management's evaluation regarding
the attainment of the defined performance goals. In April 1999, following the
Company's change to successful efforts accounting, the earnings measure for
determining return on equity as originally stated in the 1998 amendments to the
Plan was changed to allow that value measure to operate as originally intended.
Following that change, the Board of Directors determined that the 1998 value
measures applicable to the performance shares issued in 1998 were fully met. As
a result, one fourth of these performance shares have now vested. Additional
amortization expense of approximately $214,000 was recorded in the first quarter
of 1999 related to the vesting of these shares. In the second quarter of 1999,
the Company issued 132,000 performance shares and recorded deferred compensation
of approximately $1.0 million. In 1999, the Company amortized deferred
compensation of approximately $633,000 for all performance shares issued
assuming full achievement of defined performance goals.
Total Return Equity Swaps. In 1999, the Company entered into three total
return equity swap agreements with financial institutions. Under the terms of
the first agreement, entered into on February 25, 1999, the financial
institution acquired approximately 730,000 shares of HSR's common stock from
another investor at a price of $6.0625. The Company has the right, but not the
obligation, to purchase the stock at a price of $6.0625 per share at any time
through July 1, 2000.
On May 24, 1999, the Company entered into a second agreement whereby the
financial institution acquired 100,000 shares of the Company's common stock from
another investor at a price of $11.9875. The Company has the right, but not the
obligation, to purchase the stock at a price of $11.9875 per share at any time
through January 5, 2001.
On December 1, 1999, the Company entered into a third agreement whereby a
financial institution agreed to acquire on the open market up to 300,000 shares
of the Company's common stock at the current market price over a three month
period beginning December 2, 1999. As of December 31, 1999 the financial
institution had acquired 232,400 shares at a weighted average price of $14.37
per share. The Company has the right, but not the obligation, to purchase the
stock at the weighted average price at any time through September 2, 2001.
53
<PAGE> 54
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
If the Company decides not to purchase the shares on or before the
termination of these agreements, the Company will receive any increase in the
market value of the shares covered by that agreement above the purchase price of
the shares, or will pay for any loss; however, the Company may cover losses in
most circumstances by issuing common stock to the financial institution if it
chooses to do so. All such amounts will be reflected in stockholders' equity at
the time of settlement. The Company also pays certain commissions and finance
costs. At December 31, 1999 the aggregate fair market value of the Company's
common stock in excess of the underlying option price attributable to such
shares was approximately $9.4 million.
NOTE 8 -- RELATED PARTY TRANSACTIONS
In February 1999, the Company instituted the 1999 Non-Compensatory Stock
Purchase Plan. This plan is designed to enable officers of the Company to
purchase stock at fair market value in transactions exempt from Section 16(b) of
the Securities Exchange Act of 1934. Five hundred thousand shares of common
stock have been allocated to the plan. The plan is administered by the
Compensation Committee of the Board of Directors. As of December 31, 1999,
235,000 shares of common stock had been purchased at prices ranging from $5.625
to $6.50. In connection with the stock purchases, 76,000 shares were purchased
for cash. The remaining shares were purchased with the officers paying 15% of
the purchase price in cash, and the remainder in the form of full recourse
promissory notes. The notes mature on March 3, 2001 and bear interest at the
annual rate of 8.5%.
In June 1998, in connection with the exercise of stock options, certain
officers of the Company issued to the Company full recourse notes in the amount
of $2.1 million. The notes and accrued interest are due and payable to the
Company on or before June 1, 2000. The interest rate on these notes is prime
plus 0.25% per annum. The prime rate as of December 31, 1999 was 8.5%. In the
third quarter of 1999, principal and accrued interest in the amount of $823,295
was repaid.
NOTE 9 -- PROVISION FOR INCOME TAXES
The provision for income taxes consists of the following (in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
------- -------- --------
<S> <C> <C> <C>
Current:
Federal............................................. $(2,300) $ 3,100 $ 200
State............................................... 200 2,200 700
------- -------- --------
(2,100) 5,300 900
------- -------- --------
Deferred:
Federal............................................. 8,420 (14,955) (9,320)
State............................................... 873 (1,804) (1,124)
------- -------- --------
9,293 (16,759) (10,444)
------- -------- --------
$ 7,193 $(11,459) $ (9,544)
======= ======== ========
</TABLE>
54
<PAGE> 55
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The deferred income tax expense during the years ended December 31, 1999,
1998, and 1997 results from the following (in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
------- -------- --------
<S> <C> <C> <C>
TYPE OF TEMPORARY DIFFERENCE
Alternative minimum tax.............................. $ 2,600 $ (3,100) $ 50
Depreciation, depletion and amortization............. (6,895) (16,903) (17,865)
Intangible drilling costs............................ 12,192 25,428 16,530
Sales of properties.................................. (667) (28,174) (5,967)
Operating loss carryforwards......................... 2,063 5,990 (3,192)
------- -------- --------
Deferred tax provision (benefit)..................... $ 9,293 $(16,759) $(10,444)
======= ======== ========
</TABLE>
The components of the net deferred tax liability as of December 31, 1999
and 1998 are as follows (in thousands):
<TABLE>
<CAPTION>
1999 1998
------- -------
<S> <C> <C>
DEFERRED TAX LIABILITIES
Depreciation and basis difference........................... $60,817 $56,424
------- -------
Deferred tax liability...................................... 60,817 56,424
DEFERRED TAX ASSETS
Tax effect of regular net operating loss.................... 3,855 5,918
Alternative minimum tax credit.............................. 1,396 4,048
Statutory depletion carryforwards........................... 2,320 2,320
------- -------
Deferred tax assets, net.................................... 7,571 12,286
------- -------
Net deferred tax liability.................................. $53,246 $44,138
======= =======
</TABLE>
The effective tax rate during 1999, 1998 and 1997 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 $9.4 million available at December 31, 1999, to offset future
taxable income. These carryforwards, if not previously utilized, expire in 2011
through 2019.
The Company has an alternative minimum tax ("AMT") credit carryforward of
approximately $1.4 million. AMT credits can be carried forward indefinitely and
may only be used to reduce regular tax liabilities in future years when regular
tax payable exceeds AMT payable. The Company also has a percentage depletion
carryforward of approximately $6.0 million which can be used to reduce taxable
income in the future and is not subject to expiration.
NOTE 10 -- 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 and the HS Resources, Inc. Profit Sharing Plan.
Effective August 1, 1998, the two plans were merged together to form the 401(k)
and Profit Sharing Plan. Under the new plan employees are eligible to
participate upon date of hire. From January 1, 1998 through July 31, 1998,
participants could make pretax contributions up to 10%. Effective August 1, 1998
under the new plan pretax contributions increased to 15%. All annual
contributions are subject to IRS annual limitations (up to a maximum of $10,000
for 1999). Employees may receive matching contributions from the Company in an
amount determined by the Board of Directors. All 401(k) matching
55
<PAGE> 56
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
contributions are vested 100% upon eligibility. The Company can also make profit
sharing contributions. Such contributions are determined by the Board of
Directors and are vested to participants over five years of service. Company
contributions are included in general and administrative expenses in the
accompanying statements of operations.
At December 31, 1999, the Company accrued approximately $1.1 million for
the 1999 401(k) matching contribution. Contributions to the plans were $762,931
and $548,987 in 1998 and 1997, respectively.
Stock Option Plan. 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 four hundred seventy-five
thousand shares of the Company's stock are subject to the 1997 Plan. A prior
stock option plan was in effect until April 1997. The Company has two Director
Stock Option Plans, the 1992 Plan and the 1993 Plan. However no options are
outstanding under the 1993 Plan. The Company accounts for these plans under
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," under which no compensation cost was recognized during 1999, 1998
and 1997. SFAS No. 123, "Accounting for Stock Based Compensation," defines a
fair value based method of accounting for employee stock options or similar
equity instruments. However, SFAS 123 allows the continued measurement of
compensation cost for such plans using the intrinsic value based method
prescribed by APB No. 25, provided that proforma disclosures are made of net
income or loss and net income or loss per share, assuming a fair value based
method of SFAS 123 had been applied.
The following table summarizes activity with respect to outstanding stock
options for the years 1999, 1998 and 1997:
<TABLE>
<CAPTION>
THOUSANDS WEIGHTED AVERAGE
OF SHARES OPTION PRICE
--------- ----------------
<S> <C> <C>
Outstanding at December 31, 1996 (627 shares
exercisable)............................................. 774 $10.63
Granted.................................................. 163 14.60
Exercised................................................ (41) 9.23
Forfeited................................................ (7) 14.14
----- ------
Outstanding at December 31, 1997 (635 shares
exercisable)............................................. 889 11.39
Granted.................................................. 713 11.26
Exercised................................................ (379) 6.95
Forfeited................................................ (198) 14.14
----- ------
Outstanding at December 31, 1998 (448 shares
exercisable)............................................. 1,025 13.89
Granted.................................................. 509 9.59
Exercised................................................ (123) 12.32
Forfeited................................................ (20) 14.76
----- ------
Outstanding at December 31, 1999 (526 shares
exercisable)............................................. 1,391 $12.44
===== ======
</TABLE>
56
<PAGE> 57
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table reflects the pro forma financial statements had
compensation cost for the stock option plans been determined consistent with
SFAS 123, net of the effect of forfeitures and tax (in thousands except per
share amounts):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1999 1998 1997
------- -------- --------
<S> <C> <C> <C>
Net income (loss) applicable to common stockholders:
As reported........................................ $11,686 $(18,616) $(15,505)
======= ======== ========
Pro forma.......................................... $10,700 $(19,423) $(15,803)
======= ======== ========
Net income (loss) per share
As reported........................................ $ 0.62 $ (1.00) $ (0.91)
======= ======== ========
Pro forma.......................................... $ 0.57 $ (1.04) $ (0.92)
======= ======== ========
</TABLE>
The assumptions used to determine the fair value of each option grant are
as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
1999 1998 1997
----- ----- -----
<S> <C> <C> <C>
Risk-free interest rates.................................... 5.51% 4.62% 5.71%
Expected dividend yield rates............................... 0.00% 0.00% 0.00%
Expected volatility......................................... 46% 45% 40%
</TABLE>
The following table summarizes information about the stock options
outstanding at December 31, 1999:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING
---------------------- OPTIONS EXERCISABLE
WEIGHTED -------------------------
AVERAGE WEIGHTED WEIGHTED
NUMBER REMAINING AVERAGE NUMBER AVERAGE
RANGE OF OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE
EXERCISE PRICES (IN THOUSANDS) LIFE PRICE (IN THOUSANDS) PRICE
- - --------------- -------------- ----------- -------- -------------- --------
<S> <C> <C> <C> <C> <C>
$ 6.06 to $ 9.00........... 488 5.85 years $ 8.89 46 $ 8.95
$ 9.33 to $13.38........... 545 4.97 years $12.81 258 $12.71
$13.50 to $17.00........... 237 5.04 years $14.72 106 $14.85
$17.13 to $25.00........... 121 1.72 years $20.63 116 $20.79
</TABLE>
NOTE 11 -- 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 have worked together with the EPA to develop characterization
studies of the site, and have caused the facility to be permanently closed. The
Company and other non-operator respondents have completed substantially all work
at the site. The Company has incurred approximately $1.3 million as of December
31, 1999 for its portion of the costs. This amount has been recorded in the
Company's financial statements as of December 31, 1999 and the Company believes
that no substantial liability remains.
Additionally, in March of 1999 the Company became subject to an enforcement
action now being handled by the United States Environmental Protection Agency
for alleged violations of Section 404 of the Clean Water Act concerning
wetlands. The Company does not believe the result of this action will have a
57
<PAGE> 58
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
material impact on its financial position or results of operations. As of
December 31, 1999 the Company had accrued an amount in its financial statements
that it believes will be sufficient to cover the estimated settlement.
Finally, the gathering and transmission properties the Company is acquiring
from KMI contain numerous areas of polluted soil and ground water. These
conditions have been reported to the appropriate jurisdictional agencies. The
Company expects the costs associated with cleanup of these environmental
problems will be borne by KMI under the indemnification provisions of the
Company's agreement with KMI.
JW Lawsuit. On July 28, 1998, JW Resources, Inc. brought suit against the
Company and HSRTW, Inc. in the United States District Court for the Northern
District of Texas, Amarillo Division (JW Resources, Inc. v. HS Resources, Inc.
and HSRTW, Inc., Civil Action No. 2:98-CV-275). HSRTW, Inc. is now Questar
Exploration and Production Company, and is a subsidiary of Questar Corp. This
case, which was discussed in the Company's report on Form 10-Q filed May 14,
1999, has now been settled and dismissed with prejudice by the court and all
significant costs are reflected in the December 31, 1999 financial statements.
The Company is subject to minor lawsuits incidental to operations in the
oil and gas industry. The Company believes it has meritorious defenses to all
lawsuits in which it is a defendant and will vigorously defend against them. The
Company does not believe that the resolution of such lawsuits will 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, certain equipment and the Wattenberg Gathering System.
Total rental expense related to these leases was $2.4 million, $2.6 million and
$2.4 million for December 31, 1999, 1998 and 1997, respectively. Future minimum
lease payments as of December 31, 1999 are as follows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
<S> <C>
2000...................................................... $ 1,980
2001...................................................... 1,724
2002...................................................... 6,114
2003...................................................... 2,352
2004...................................................... 141
Thereafter................................................ 547
-------
Total minimum lease payments.................... $12,858
=======
</TABLE>
Wattenberg Gathering System Lease Agreement. In connection with the
acquisition of the Wattenberg Gathering System, the Company will likely assume
the operating lease for the gathering system on January 1, 2002. Once the lease
is assumed the Company will be required to make quarterly payments of $1.1
million from March 30, 2002 through March 30, 2003. As of March 30, 2003 the
Company has the following options: exercise the option to purchase the equipment
for $19.9 million, terminate the lease, or renegotiate and extend the terms of
the lease. As of December 31, 1999, the Company is also obligated to make
quarterly supplemental interest payments on the outstanding lease balance for
the difference between the fixed rate of 6.65% and the three month LIBOR rate
plus 2.00%.
NOTE 12 -- OTHER GAS REVENUES
The Company and its subsidiaries continue to enter into transactions
designed to monetize the Company's Section 29 tax credits. In thirteen separate
transactions through December 31, 1999 (and one in 2000), 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 while retaining a volumetric production payment that entitles
it to 100% of the net cash flows from the properties. The sale
58
<PAGE> 59
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
will enable the third parties to earn tax credits associated with future oil and
gas production. In 1999, 1998 and 1997, the Company received approximately $0.3
million, $6.4 million and $10.6 million, respectively, in prepaid tax credit
payments. The Company recorded the proceeds as deferred revenue and is
amortizing the amount to other gas revenues as the gas is produced and the
credits are generated. The Company recognized approximately $10.1 million, $8.6
million and $4.4 million of other gas revenues associated with all tax credits
during the years ended December 31, 1999, 1998 and 1997, respectively.
NOTE 13 -- OIL AND GAS ACTIVITIES
Major Purchasers. In 1999, sales to Duke Energy Field Service, BP Amoco and
Ultramar Diamond Shamrock Corporation accounted for approximately $30.6 million,
$22.1 million and $15.4 million or 18.6%, 13.4% and 9.3% of total oil and gas
sales, respectively. In 1998, sales to Duke Energy Field Service, BP Amoco and
Ultramar Diamond Shamrock Corporation accounted for approximately $26.4 million,
$15.7 million and $15.2 million or 17.6%, 10.5% and 10.1% of total oil and gas
sales, respectively. In 1997, sales to Duke Energy Field Service and BP Amoco
accounted for approximately $28.7 million and $23.3 million or 20.9% and 17.0%
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 barrel of oil
production are as follows (in thousands except DD&A rate):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
------- -------- ---------
<S> <C> <C> <C>
Property acquisition costs
Unproved........................................... $12,908 $ 15,414 $ 130,169
Proved............................................. $ 201 $ 12,615 $ 226,458
------- -------- ---------
Exploration costs.................................... $ 6,490 $ 10,747 $ 12,856
------- -------- ---------
Development costs.................................... $67,760 $ 78,736 $ 44,375
------- -------- ---------
Depreciation, depletion and amortization............. $52,435 $ 58,992 $ 43,421
------- -------- ---------
Depreciation, depletion and amortization per
equivalent barrel of oil production................ $ 4.30 $ 4.87 $ 4.69
======= ======== =========
</TABLE>
59
<PAGE> 60
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 14 -- BUSINESS SEGMENT INFORMATION
The Company is an independent energy company engaged in the following
activities:
- acquisition, development, exploitation, exploration and production of oil
and gas
- transportation and marketing of oil and gas
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1999 1998 1997
---------- -------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Operating Revenues:
Oil and gas sales D-J Basin............................ $ 155,169 $139,259 $ 96,357
Oil and gas sales Gulf Coast........................... 19,365 2,344 1,754
Oil and gas sales Mid-Continent and other.............. 258 17,045 43,589
Gas gathering and transportation facilities............ 1,286 -- --
Trading and transportation............................. 170,232 142,374 148,994
Intersegment eliminations.............................. (117,570) (88,231) (58,932)
---------- -------- ----------
$ 228,740 $212,791 $ 231,762
========== ======== ==========
Operating Income (Loss):
D-J Basin.............................................. $ 67,839 $ 51,538 $ 47,144
Gulf Coast............................................. (2,702) (19,471) (20,265)
Mid-Continent and other................................ (742) (15,252) (9,638)
Gas gathering and transportation facilities............ 900 -- --
Trading and transportation............................. 5,133 5,713 1,960
Intersegment eliminations.............................. (2,472) (2,436) (681)
---------- -------- ----------
Operating Income......................................... 67,956 20,092 18,520
Other income and expense............................... (49,077) (50,167) (43,569)
---------- -------- ----------
Income (Loss) before income taxes........................ $ 18,879 $(30,075) $ (25,049)
========== ======== ==========
Identifiable Assets (at December 31):
Oil and gas properties D-J Basin....................... $ 952,817 $898,647 $ 820,481
Oil and gas properties Gulf Coast...................... 34,291 21,750 13,306
Oil and gas properties Mid-Continent and other......... 6,101 4,267 195,110
Gas gathering and transportation facilities............ 54,627 5,891 5,863
Trading and transportation............................. 3,849 3,786 3,735
Corporate.............................................. 8,468 8,715 9,684
---------- -------- ----------
$1,060,153 $943,056 $1,048,179
========== ======== ==========
Depreciation, Depletion and Amortization Expense:
Oil and gas properties D-J Basin....................... $ 49,655 $ 50,735 $ 23,147
Oil and gas properties Gulf Coast...................... 3,158 510 274
Oil and gas properties Mid-Continent and other......... 70 8,042 20,290
Trading and transportation............................. 434 416 382
Corporate.............................................. 1,083 1,520 1,664
---------- -------- ----------
$ 54,400 $ 61,223 $ 45,757
========== ======== ==========
Capital Expenditures and Acquisitions:
Oil and gas properties D-J Basin....................... $ 56,682 $ 71,139 $ 324,156
Oil and gas properties Gulf Coast...................... 16,739 14,418 9,387
Oil and gas properties Mid-Continent and other......... 2,663 17,504 11,733
Gas gathering and transportation facilities............ 48,736 28 157
Trading and transportation............................. 62 51 17
Corporate.............................................. 446 838 1,695
---------- -------- ----------
$ 125,328 $103,978 $ 347,145
========== ======== ==========
</TABLE>
60
<PAGE> 61
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 15 -- 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, 1999, 1998 and 1997. All
such reserves are located in the United States. The amounts as of December 31,
1999, 1998 and 1997, were prepared by the Company and substantially all were
reviewed by either Netherland, Sewell & Associates, Inc. or by Williamson
Petroleum Consultants, Inc., each an independent petroleum engineering
consulting firm. For a discussion of the extent of such review see Item 2.
"Properties -- Oil and Gas Reserves."
ANALYSIS OF CHANGES IN PROVED RESERVES
<TABLE>
<CAPTION>
OIL GAS
PROVED DEVELOPED AND UNDEVELOPED RESERVES (MBBL) (MMCF)
- - ----------------------------------------- ------ --------
<S> <C> <C>
Balance, December 31, 1996.................................. 34,614 644,421
Revision of previous estimates............................ (2,727) (36,810)
Extensions, discoveries and other additions............... 2,099 42,623
Production................................................ (2,400) (41,125)
Purchases of reserves in place............................ 14,840 332,794
Sales of reserves in place................................ (1,068) (62,049)
------ --------
Balance, December 31, 1997.................................. 45,358 879,854
Revision of previous estimates............................ (7,025) (54,286)
Extensions, discoveries and other additions............... 5,878 185,208
Production................................................ (2,630) (56,969)
Purchases of reserves in place............................ 392 7,672
Sales of reserves in place................................ (4,529) (164,430)
------ --------
Balance, December 31, 1998.................................. 37,444 797,049
Revision of previous estimates............................ 2,600 7,230
Extensions, discoveries and other additions............... 2,975 128,768
Production................................................ (2,410) (58,799)
Purchases of reserves in place............................ 443 5,627
Sales of reserves in place................................ (424) (12,094)
------ --------
Balance, December 31, 1999.................................. 40,628 867,781
====== ========
Proved developed reserves
December 31, 1997......................................... 26,028 611,198
====== ========
December 31, 1998......................................... 23,558 561,410
====== ========
December 31, 1999......................................... 24,268 585,465
====== ========
</TABLE>
61
<PAGE> 62
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Standardized Measure. The standardized measure of discounted future net
cash flows, and changes therein related to proved oil and gas reserves are as
follows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Future cash inflows..................................... $3,117,797 $1,923,811 $2,771,498
Future production costs................................. (595,244) (460,431) (681,825)
Future development costs................................ (398,115) (335,904) (360,007)
---------- ---------- ----------
Undiscounted future pre-tax cash flows.................. 2,124,438 1,127,476 1,729,666
Undiscounted future income taxes........................ (549,471) (215,320) (410,680)
---------- ---------- ----------
Undiscounted future pre-tax cash flows, net of future
income taxes.......................................... 1,574,967 912,156 1,318,986
10% discount factor..................................... (794,918) (476,276) (689,535)
---------- ---------- ----------
Standardized measure of discounted future net cash
flows................................................. $ 780,049 $ 435,880 $ 629,451
---------- ---------- ----------
Discounted future pre-tax cash flows excluding income
taxes................................................. $1,051,064 $ 531,905 $ 822,467
========== ========== ==========
</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.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
Standardized measure of discounted future net cash flows,
beginning of the year................................... $ 435,880 $ 629,451 $ 818,018
Sales and transfers of oil and gas produced, net of
production costs........................................ (124,467) (108,623) (101,796)
Sales of reserves in place................................ (5,738) (157,547) (63,972)
Net changes in prices and production costs on beginning of
year reserves........................................... 373,733 (199,052) (464,697)
Extensions, discoveries and improved recovery, less
related
costs................................................... 159,851 162,530 60,510
Changes in future development costs....................... (70,528) 2,808 (22,474)
Development costs incurred during the period that reduced
future development costs................................ 67,937 78,540 43,489
Revisions of previous quantity estimates.................. 24,374 (55,618) (46,872)
Purchase of reserves in place............................. 9,153 6,328 265,064
Accretion of discount..................................... 53,191 73,099 113,283
Net change in income taxes................................ (174,990) 5,518 121,793
Changes in production rates (timing) and other............ 31,653 (1,554) (92,895)
--------- --------- ---------
Standardized measure of discounted future net cash flows,
end of the year......................................... $ 780,049 $ 435,880 $ 629,451
========= ========= =========
</TABLE>
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 estimat-
62
<PAGE> 63
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ing 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 $23.55/Bbl of oil and $2.49/Mcf of gas at December 31, 1999,
$9.99/Bbl of oil and $1.94/Mcf of gas at December 31, 1998, and $16.38/Bbl of
oil and $2.31/Mcf of gas at December 31, 1997.
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. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Disclosure Regarding Forward Looking Statements" and "Certain
Considerations -- Estimation of Reserves."
NOTE 16 -- QUARTERLY FINANCIAL DATA (UNAUDITED)
The Company's quarterly results of operations are summarized as follows (in
thousands, except per share data):
<TABLE>
<CAPTION>
1999
---------------------------------------
MAR. 31 JUNE 30 SEPT. 30 DEC. 31
------- ------- -------- --------
<S> <C> <C> <C> <C>
Operating revenues.......................... $47,912 $51,216 $57,350 $ 72,263
Operating expenses.......................... 36,058 39,561 37,538 48,710
------- ------- ------- --------
Operating income............................ 11,854 11,655 19,812 23,553
------- ------- ------- --------
Net income.................................. $ 106 $ 119 $ 4,809 $ 6,652
------- ------- ------- --------
Diluted earnings per share.................. $ 0.01 $ 0.01 $ 0.25 $ 0.35
------- ------- ------- --------
</TABLE>
63
<PAGE> 64
HS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
1998
---------------------------------------
MAR. 31 JUNE 30 SEPT. 30 DEC. 31
------- ------- -------- --------
<S> <C> <C> <C> <C>
Operating revenues.......................... $63,565 $51,759 $48,786 $ 48,681
Operating expenses.......................... 44,556 44,237 49,294 56,133
------- ------- ------- --------
Operating income (loss)..................... 19,009 7,522 (508) (7,452)
------- ------- ------- --------
Net income (loss)........................... $ 4,081 $(3,257) $(8,134) $(11,307)
------- ------- ------- --------
Diluted earnings (loss) per share........... $ 0.22 $ (0.18) $ (0.43) $ (0.61)
------- ------- ------- --------
</TABLE>
<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.......................... 53,664 42,788 44,183 74,271
------- ------- ------- --------
Operating income (loss)..................... 12,295 7,349 5,066 (7,854)
------- ------- ------- --------
Net income (loss)........................... $ 1,458 $(1,270) $(2,932) $(12,761)
------- ------- ------- --------
Diluted earnings (loss) per share........... $ 0.08 $ (0.07) $ (0.17) $ (0.73)
------- ------- ------- --------
</TABLE>
64
<PAGE> 65
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
PART III
ITEMS 10-13, INCLUSIVE:
These items have been omitted in accordance with the instructions of Form
10-K. Pursuant to Regulation 14A of the Securities Exchange Act, the Registrant
will file with the Commission on or before April 30, 2000, a definitive proxy
statement which will include information responsive to the above Items.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, AND REPORTS ON FORM 8-K
(a) Exhibits.
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
<C> <S>
3.1 -- Amended and Restated Certificate of Incorporation of the
Company. (Incorporated herein by reference to Exhibit 3.1
to the Company's Registration Statement on Form S-1, No.
33-52774, filed October 2, 1992.)
3.2 -- Certificate of Amendment of Certificate of Incorporation
filed November 30, 1998. (Incorporated by reference to
Exhibit 3.2 to the Company's Quarterly Report on Form
10-Q for the quarter ended March 31, 1999, filed May 14,
1999.)
3.3 -- Third Amended and Restated Bylaws of the Company adopted
December 16, 1996. (Incorporated by reference to Exhibit
3.2 to the Company's Registration Statement on Form S-4,
No. 333-19433, filed January 8, 1997.)
4.1 -- Form of Indenture dated December 1, 1993, entered into
between the Company and the Trustee. (Incorporated by
reference to Exhibit 4.7 to Amendment No. 3 to the
Company's Registration Statement on Form S-3, No.
33-70354, filed November 23, 1993.)
4.2 -- Indenture dated November 27, 1996, among the Company,
Orion Acquisition, Inc., HSRTW, Inc., and Harris Trust
and Savings Bank as Trustee. (Incorporated by reference
to Exhibit 4.2 to the Company's Registration Statement on
Form S-4, No. 333-19433, filed January 8, 1997.)
4.3 -- First Supplemental Indenture dated November 25, 1996
among the Company, Orion Acquisition, Inc., HSRTW, Inc.,
and Harris Trust and Savings Bank as Trustee.
(Incorporated by reference to Exhibit 4.3 to the
Company's Registration Statement on Form S-4, No.
333-19433, filed January 8, 1997.)
10.1 -- Common Stock Purchase Warrant dated July 12, 1990 by the
Company to James E. Duffy. (Incorporated by reference to
Exhibit 10.5 to the Form 8, Second Amendment to Form 10,
filed April 8, 1991.)
10.2 -- HS Resources, Inc. Rule 701 Compensatory Benefit Plan.
(Incorporated by reference to Exhibit 10.5.2 to the Form
8, Second Amendment to Form 10, filed April 8, 1991.)
10.3 -- 1992 Directors' Stock Option Plan. (Incorporated by
reference to Exhibit 10.10 to Amendment No. 1 to the
Company's Registration Statement on Form S-1, No.
33-52774, filed November 9, 1992.)
</TABLE>
65
<PAGE> 66
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
<C> <S>
10.3.1 -- 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.))
10.4 -- Form of Indemnification Agreement for Directors of the
Company. (Incorporated by reference to Exhibit 10.16 to
the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1995, filed March 25, 1996.)
10.5 -- Lease Agreement dated October 6, 1993, between the
Company and JMB Group Trust IV and Endowment and
Foundation Realty, Ltd. -- JMB III for the premises at
One Maritime Plaza, San Francisco, California.
(Incorporated by reference to Exhibit 10.13 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1993, filed March 31, 1994 (as amended
by Form 10-K/A-1 on April 8, 1994.))
10.6 -- Lease Agreement dated March 28, 1994, between the Company
and 1999 Broadway Partnership for the premises at 1999
Broadway, Denver, Colorado. (Incorporated by reference to
Exhibit 10.15 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1994, filed August
12, 1994.)
10.7 -- Purchase and Sale Agreement, dated December 1, 1995,
between the Company and Wattenberg Gas Investments, LLC.
(Incorporated by reference to Exhibit 10.26 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1995, filed March 25, 1996.)
10.8 -- Rights Agreement, dated as of February 28, 1996, between
the Company and Harris Trust Company of California as
Rights Agent. (Incorporated by reference to Exhibit 1 to
the Company's Form 8-A, filed March 11, 1996.)
10.9 -- Purchase and Sale Agreement dated March 25, 1996, between
Orion, the Company and Wattenberg Resources Land, L.L.C.
(Incorporated by reference to Exhibit 10.28 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1996, filed May 15, 1996.)
10.10 -- Amended and Restated Credit Agreement dated as of June
14, 1996, among the Company, Chase as agent, and the
Banks signatory thereto. (Incorporated by reference to
Exhibit 10.21 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, filed August
14, 1996.)
10.11 -- First Amendment to Amended and Restated Credit Agreement
dated as of June 17, 1996, by and among the Company and
Chase in its individual capacity and as agent for the
Lenders. (Incorporated by reference to Exhibit 10.22 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
10.12 -- Second Amendment to Amended and Restated Credit Agreement
dated as of November 27, 1996 among the Company and Chase
in its individual capacity and as agent for the Lenders.
(Incorporated by reference to Exhibit 10.22 to the
Company's Registration Statement on Form S-4, No.
333-19433, filed January 8, 1997.)
10.13 -- Purchase and Sale Agreement between the Company and
Wattenberg Gas Investments, LLC dated April 25, 1996.
(Incorporated by reference to Exhibit 10.32 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1996, filed August 14, 1996.)
10.14 -- Purchase and Sale Agreement between Wattenberg Resources
Land L.L.C. and Wattenberg Gas Investments, LLC dated May
21, 1996. (Incorporated by reference to Exhibit 10.33 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
</TABLE>
66
<PAGE> 67
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
<C> <S>
10.15 -- Purchase and Sale Agreement between Orion and Wattenberg
Gas Investments, LLC dated June 14, 1996. (Incorporated
by reference to Exhibit 10.34 to the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1996,
filed August 14, 1996.)
10.16 -- Purchase and Sale Agreement between Wattenberg Resources
Land L.L.C. and Wattenberg Gas Investments, LLC dated
June 14, 1996. (Incorporated by reference to Exhibit
10.35 to the Company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 1996, filed August 14, 1996.)
10.17 -- Purchase and Sale Agreement between Orion and Wattenberg
Gas Investments, LLC dated June 14, 1996. (Incorporated
by reference to Exhibit 10.36 to the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1996,
filed August 14, 1996.)
10.18 -- Purchase and Sale Agreement between the Company and
Wattenberg Gas Investments, LLC dated June 28, 1996.
(Incorporated by reference to Exhibit 10.37 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1996, filed August 14, 1996.)
10.19 -- Purchase and Sale Agreement between 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.)
10.20 -- 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.)
10.21 -- 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.)
10.22 -- 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.)
10.23 -- 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.)
10.24 -- 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.)
10.25 -- Purchase and Sale Agreement dated December 15, 1997, by
and between HS Resources, Inc. as Seller and WestTide
Investments, LLC as Buyer. (Incorporated by reference to
Exhibit 10.46 to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1997, filed March
31, 1998.)
10.26 -- Fifth Amendment and Supplement to Amended, Restated and
Consolidated Mortgage, Assignment of Production, Security
Agreement and Financing Statement between HS Resources
(Mortgagor) and The Chase Manhattan Bank, as agent for
the Lenders, effective as of December 15, 1997.
(Incorporated by reference to Exhibit 10.37 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1998, filed May 14, 1998.)
</TABLE>
67
<PAGE> 68
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
<C> <S>
10.27 -- Agreement and Plan of Merger between Orion Acquisition,
Inc. and HS Resources, Inc. dated April 20, 1998, but
effective May 1, 1998. (Incorporated by reference to
Exhibit 10.38 to the Company's Quarterly Report on Form
10-Q for the quarter ended March 31, 1998, filed May 14,
1998.)
10.28 -- First Amendment to Agreement of Lease between 1999
Broadway Partnership (Landlord) and HS Resources, Inc.
(Tenant), dated March 21, 1997. (Incorporated by
reference to Exhibit 10.39 to the Company's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1998,
filed May 14, 1998.)
10.29 -- HS Resources, Inc. Form of Key Employee Severance
Agreement (March 27, 1998). (Incorporated by reference to
Exhibit 10.40 to the Company's Quarterly Report on Form
10-Q for the quarter ended March 31, 1998, filed May 14,
1998.)
10.30 -- Fourth Amendment to Amended and Restated Credit Agreement
dated as of June 16, 1998, among the Company and The
Chase Manhattan Bank in its individual capacity and as
agent for the Lenders. (Incorporated by reference to
Exhibit 10.41 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1998, filed August
14, 1998.)
10.31 -- Stock Purchase and Sale Agreement between the Company and
Universal Resources Corporation dated July 27, 1998.
(Incorporated by reference to Exhibit 10.1 to the
Company's Form 8-K, filed August 6, 1998.)
10.32 -- Fifth Amendment to Amended and Restated Credit Agreement
dated as of September 1, 1998, among the Company and The
Chase Manhattan Bank in its individual capacity and as
agent for the lenders. (Incorporated by reference to
Exhibit 10.37 to the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1998, filed
November 16, 1998.)
10.33 -- Sixth Amendment and Supplement to Amended, Restated and
Consolidated Mortgage, Assignment of Production, Security
Agreement and Financing Statement dated as of July 22,
1998, among the Company and The Chase Manhattan Bank in
its individual capacity and as agent for the Lenders.
(Incorporated by reference to Exhibit 10.38 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended September 30, 1998, filed November 16, 1998.)
10.34 -- Sixth Amendment to Amended and Restated Credit Agreement
dated as of December 10, 1998, among the Company and The
Chase Manhattan Bank in its individual capacity and as
agent for the Lenders. (Incorporated by reference to
Exhibit 10.40 to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1998, filed March
31, 1999.)
10.35 -- Seventh Amendment to Amended and Restated Credit
Agreement dated as of December 31, 1998, among the
Company and The Chase Manhattan Bank in its individual
capacity and as agent for the Lenders. (Incorporated by
reference to Exhibit 10.41 to the Company's Annual Report
on Form 10-K for the fiscal year ended December 31, 1998,
filed March 31, 1999.)
10.36 -- 1999 Non-Compensatory Stock Purchase Plan. (Incorporated
by reference as Exhibit 4.1 to Form S-8 filed January 25,
1999.)
10.37 -- Supplemental Indenture dated as of March 1, 1999, among
the Company and Harris Trust and Savings Bank as Trustee,
amending Indenture dated as of December 1, 1993,
concerning 9 7/8% Senior Subordinated Notes due 2003.
(Incorporated by reference to Exhibit 10.43 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1998, filed March 31, 1999.)
</TABLE>
68
<PAGE> 69
<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
<C> <S>
10.38 -- Supplemental Indenture dated as of March 1, 1999, among
the Company and Harris Trust and Savings Bank as Trustee,
amending Indenture dated as of November 27, 1996,
concerning 9 1/4% Series A Senior Subordinated Notes due
2006. (Incorporated by reference to Exhibit 10.44 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1998, filed March 31, 1999.)
10.39 -- Supplemental Indenture dated as of March 1, 1999, among
the Company and Harris Trust and Savings Bank as Trustee,
amending Indenture dated as of December 11, 1998,
concerning 9 1/4% Series B Senior Subordinated Notes due
2006. (Incorporated by reference to Exhibit 10.45 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1998, filed March 31, 1999.)
10.40 -- Seventh Amendment and Supplement to Amended, Restated and
Consolidated Mortgage, Assignment of Production, Security
Agreement and Financing Statement dated as of September
1, 1999 among: The Company and The Chase Manhattan Bank
in its individual capacity, and as agent to the Lenders.
(Incorporated by reference to Exhibit 10.41 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended September 30, 1999, filed November 15, 1999).
10.41 -- Eighth Amendment to Amended and Restated Credit Agreement
dated as of August 27, 1999 among: The Company and The
Chase Manhattan Bank in its individual capacity, and as
agent for the Lenders. (Incorporated by reference to
Exhibit 10.42 to the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1999, filed
November 15, 1999).
10.42 -- Exchange Agreement dated August 27, 1999 between HS
Resources, Inc. and Patina Oil & Gas Corporation.
(Incorporated by reference to Exhibit 10.43 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended September 30, 1999, filed November 15, 1999).
10.43* -- Ninth Amendment to Amended and Restated Credit Agreement
dated as of October 28, 1999 among: The Company and The
Chase Manhattan Bank in its individual capacity, and as
agent for the Lenders.
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>
- - ---------------
* Filed herewith
b. Reports on Form 8-K.
Report dated November 9, 1999, filing the October 26, 1999 press
release in connection with the Company's third quarter earnings release.
Item 5.
Report dated December 13, 1999, relating to the November 26, 1999
acquisition from Kinder Morgan, Inc. Item 2.
69
<PAGE> 70
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, on this 24th 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 24th day of March.
<TABLE>
<CAPTION>
SIGNATURE TITLE
--------- -----
<C> <S>
/s/ NICHOLAS J. SUTTON Chairman of the Board, Chief Executive
- - ----------------------------------------------------- Officer (Principal Executive Officer)
Nicholas J. Sutton
/s/ P. MICHAEL HIGHUM President and Director
- - -----------------------------------------------------
P. Michael Highum
/s/ JAMES E. DUFFY Chief Financial Officer and Director
- - ----------------------------------------------------- (Principal Financial Officer)
James E. Duffy
/s/ ANNETTE MONTOYA Vice President -- Accounting and Controller
- - ----------------------------------------------------- (Principal Accounting Officer)
Annette Montoya
/s/ MICHAEL J. SAVAGE Director
- - -----------------------------------------------------
Michael J. Savage
BARRY REDER Director
- - -----------------------------------------------------
Barry Reder
ROBERT G. VANNEMAN Director
- - -----------------------------------------------------
Robert G. Vanneman
</TABLE>
70
<PAGE> 71
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
10.43* -- Ninth Amendment to Amended and Restated Credit Agreement
dated as of October 28, 1999 among: The Company and The
Chase Manhattan Bank in its individual capacity, and as
agent for the Lenders.
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>
- - ---------------
* Filed herewith
<PAGE> 1
EXHIBIT 10.43
NINTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT
THIS NINTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this
"Amendment") is dated as of October 28, 1999 among: HS RESOURCES, INC., a
corporation formed under the laws of the State of Delaware (the "Borrower");
each of the lenders that is a signatory hereto; and THE CHASE MANHATTAN BANK (in
its individual capacity, "Chase"), as agent for the Lenders (in such capacity,
together with its successors in such capacity, the "Agent").
R E C I T A L S
---------------
A. The Borrower, the Agent, and the Lenders (as defined in the Credit
Agreement as hereafter defined) have entered into that certain Amended and
Restated Credit Agreement dated as of June 14, 1996, as amended by the First
Amendment to Amended and Restated Credit Agreement dated as of June 17, 1996,
the Second Amendment to Amended and Restated Credit Agreement dated as of
November 27, 1996, the Third Amendment to Amended and Restated Credit Agreement
dated as of December 15, 1997, the Fourth Amendment to Amended and Restated
Credit Agreement dated as of June 16, 1998, the Fifth Amendment to Amended and
Restated Credit Agreement dated as of September 1, 1998, the Sixth Amendment to
Amended and Restated Credit Agreement dated as of December 10, 1998, the Seventh
Amendment to Amended and Restated Credit Agreement dated as of December 31, 1998
and the Eighth Amendment to Amended and Restated Credit Agreement dated as of
August 27, 1999 (as amended, the "Credit Agreement"), pursuant to which the
Lenders have agreed to make certain loans and extensions of credit to the
Borrower upon the terms and conditions as provided therein;
B. The Borrower has entered into negotiations with KN Energy, Inc. (now
Kinder-Morgan, Inc.("KMI")) to acquire KMI's Wattenberg gathering and
transmission assets and in connection therewith, KMI and KN Gas Gathering, Inc.,
("KNGG"), as Sellers, and the Borrower, as Buyer, will execute that certain
Purchase and Sale Agreement and KNGG and the Borrower will execute that certain
Operating Services Agreement, both to be dated on or about October 29, 1999,
together such agreements providing substantially the following:
(i) Sellers would sell and Buyer would purchase the Sellers'
Wattenberg gathering and transmissions system located in Adams,
Arapahoe, Boulder, Denver, Larimer and Weld Counties, Colorado,
including without limitation, rights in a lease as lessee covering some
or all of such Property ("Wattenberg Gathering System");
(ii) The Borrower would commence operation of the Wattenberg
Gathering System on November 1, 1999. The Borrower would be obligated
to pay the costs of operating the Wattenberg Gathering System and would
bear the risk of uninsured loss. KNGG would pay the Borrower a fixed
fee that is expected to equal the costs of operating the Wattenberg
Gathering System;
(iii) Sellers would retain legal title or lease rights to the
Wattenberg Gathering System until the Closing, to be held on or about
December 15, 2001;
-1-
<PAGE> 2
(iv) The Borrower would pay $1,000,000 in cash on or about
October 29, 1999;
(v) The Borrower would extend its commitment of gas to the
Wattenberg Gathering System through December 31, 2001, under the terms
of existing gathering agreements;
(vi) The Borrower would pay a facility fee of $360,000 per
month from January 2000 through December 2001;
(vii) Sellers would retain Wattenberg Gathering System gross
margin revenue through December 31, 2001, provided that the Borrower
would pay Sellers any shortfall below 95% of currently projected gross
margin revenue of approximately $2,300,000 per month and the Borrower
would receive any excess above 105% of that amount; and
(viii) The Borrower would make a final payment at Closing of
$30,000,000, consisting of a cash payment of approximately $7,000,000
and an assumption of an operating lease concerning gathering equipment
with a projected balance as of closing of approximately $23,000,000.
C. The Borrower, the Agent, and the Lenders now desire to make certain
amendments to the Credit Agreement to permit such acquisition.
NOW, THEREFORE, in consideration of the premises and other good and
valuable consideration and the mutual benefits, covenants and agreements herein
expressed, the parties hereto now agree as follows:
1. All capitalized terms used in this Amendment and not otherwise
defined herein shall have the meanings ascribed to such terms in the Credit
Agreement.
2. Section 1.02 of the Credit Agreement is hereby supplemented, where
alphabetically appropriate, with the addition of the following definitions:
"Ninth Amendment" shall mean that certain Ninth Amendment to
Amended and Restated Credit Agreement dated as of October 28, 1999,
among the Borrower, the Lenders and the Agent.
"Wattenberg Gathering System" shall have the meaning assigned
in the Recitals to the Ninth Amendment.
-2-
<PAGE> 3
3. Section 9.01 of the Credit Agreement is hereby amended by adding the
following clause (p):
"(p) the consideration to be paid, performed and assumed by
the Borrower or HS Gathering, LLC for the acquisition of the Wattenberg
Gathering System as described in the Recitals to the Ninth Amendment,
and a guaranty by the Borrower of the obligations of the current lessee
under the operating lease as well as the obligations of HS Gathering,
LLC as a result of the assumption of such lease."
4. Section 9.02 of the Credit Agreement is hereby amended by adding the
following clause (h):
"(h) a Lien on certain Properties of the Wattenberg Gathering
System owned by HS Gathering, LLC to secure Debt assumed or incurred to
acquire the Wattenberg Gathering System and all extension, renewals and
replacements of such Debt."
5. Section 9.03(m) of the Credit Agreement is hereby amended by adding
the following before the semi-colon at the end of the clause:
"and an investment by the Borrower and its Subsidiaries in the
Wattenberg Gathering System through the Borrower's 100% ownership of HS
Gathering, LLC and KN Wattenberg Transmission, LLC"
6. Section 9.18 of the Credit Agreement is hereby amended by adding the
following before the period at the end of the first sentence in such section:
", other than HS Gathering, LLC and KN Wattenberg Transmission, LLC,
which will be 100% owned by the Borrower"
7. This Amendment shall become binding on the Lenders when, and only
when, the following conditions shall have been satisfied and the Agent shall
have received each of the following, as applicable, in form and substance
satisfactory to the Agent or its counsel:
(a) counterparts of this Amendment executed by the Borrower
and the Majority Lenders;
(b) a Guaranty Agreement executed by HS Gathering, LLC; and
(c) the execution, delivery and effectiveness of the Purchase
and Sale Agreement covering the sale of the Wattenberg Gathering System
to the Borrower and HS Gathering, LLC.
8. The parties hereto hereby acknowledge and agree that, except as
specifically supplemented and amended, changed or modified hereby, the Credit
Agreement shall remain in full force and effect in accordance with its terms.
-3-
<PAGE> 4
9. The Borrower hereby reaffirms that as of the date of this Amendment,
the representations and warranties contained in Article VII of the Credit
Agreement are true and correct on the date hereof as though made on and as of
the date of this Amendment, except as such representations and warranties are
expressly limited to an earlier date.
10. THIS AMENDMENT (INCLUDING, BUT NOT LIMITED TO, THE VALIDITY AND
ENFORCEABILITY HEREOF) SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH,
THE LAWS OF THE STATE OF NEW YORK.
11. This Amendment may be executed in two or more counterparts, and it
shall not be necessary that the signatures of all parties hereto be contained on
any one counterpart hereof; each counterpart shall be deemed an original, but
all of which together shall constitute one and the same instrument. Delivery of
an executed signature page of this Amendment by facsimile transmission shall be
effective as delivery of a manually executed counterpart hereof.
[SIGNATURES BEGIN NEXT PAGE]
-4-
<PAGE> 5
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be
executed as of the date set forth in the opening paragraph of this Amendment..
BORROWER: HS RESOURCES, INC.
By:
---------------------------------
Name:
Title:
LENDER AND AGENT: THE CHASE MANHATTAN BANK
By:
---------------------------------
Name:
Title:
LENDERS: ABN AMRO BANK N.V.
San Francisco International Branch
By:
---------------------------------
Name:
Title:
By:
---------------------------------
Name:
Title:
CREDIT LYONNAIS NEW YORK BRANCH
By:
---------------------------------
Name:
Title:
S-1
<PAGE> 6
UNION BANK OF CALIFORNIA, N.A.
By:
---------------------------------
Name:
Title:
WELLS FARGO BANK, N.A.
By:
---------------------------------
Name:
Title:
PARIBAS
By:
---------------------------------
Name:
Title:
By:
---------------------------------
Name:
Title:
BANK ONE, NA (FORMERLY KNOWN AS
FIRST NATIONAL BANK OF CHICAGO)
By:
---------------------------------
Name:
Title:
GENERAL ELECTRIC CAPITAL
CORPORATION
By:
---------------------------------
Name:
Title:
S-2
<PAGE> 7
MEESPIERSON CAPITAL CORP.
By:
---------------------------------
Name:
Title:
By:
---------------------------------
Name:
Title:
ROYAL BANK OF CANADA
By:
---------------------------------
Name:
Title:
BANK OF SCOTLAND
By:
---------------------------------
Name:
Title:
FIRST UNION NATIONAL BANK
By:
---------------------------------
Name:
Title:
S-3
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to incorporation by
reference 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, 33-91934, 333-66329 and 333-71107.
/s/ Arthur Andersen LLP
------------------------
Arthur Andersen LLP
Denver, Colorado
March 24, 2000
<PAGE> 1
EXHIBIT 23.2
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 to be filed with the Securities and Exchange Commission (the
Commission) on or about March 24, 2000, (ii) incorporation of the foregoing by
reference in (a) the HS Resources, Inc. Registration Statement on Form S-3
initially filed with the Commission on February 5, 1997, and any amendments
thereof, (b) the HS Resources, Inc. Registration Statement on 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, May 5, 1995, October 29, 1998, and January 25, 1999, and any
amendments thereof.
/s/ Williamson Petroleum Consultants, Inc.
-------------------------------------------
Williamson Petroleum Consultants, Inc.
Midland, Texas
March 24, 2000
<PAGE> 1
EXHIBIT 23.3
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, 1999, filed with the
Securities and Exchange Commission (SEC) on or about March 24, 2000, and the
incorporation of the foregoing by reference in (a) the HS Resources, Inc.
Registration Statement on Form S-3 initially filed with the SEC on February 5,
1997, and any amendments thereof; (b) the HS Resources, Inc. Registration
Statement on 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, May 5, 1995, October 29, 1998, and January 25, 1999,
and any amendments thereof.
/s/ Netherland, Sewell & Associates, Inc.
------------------------------------------
Netherland, Sewell & Associates, Inc.
Dallas, Texas
March 24, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 518,215
<SECURITIES> 0
<RECEIVABLES> 70,993,616
<ALLOWANCES> 0
<INVENTORY> 1,249,359
<CURRENT-ASSETS> 77,661,623
<PP&E> 1,056,553,944
<DEPRECIATION> 236,259,967
<TOTAL-ASSETS> 911,178,219
<CURRENT-LIABILITIES> 114,595,343
<BONDS> 560,140,568
0
0
<COMMON> 19,527
<OTHER-SE> 167,373,049
<TOTAL-LIABILITY-AND-EQUITY> 911,178,219
<SALES> 218,608,086
<TOTAL-REVENUES> 229,350,171
<CGS> 49,952,992
<TOTAL-COSTS> 117,737,631
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 42,781,026
<INCOME-PRETAX> 18,878,522
<INCOME-TAX> 7,192,717
<INCOME-CONTINUING> 11,685,805
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 11,685,805
<EPS-BASIC> 0.63
<EPS-DILUTED> 0.62
</TABLE>
