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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the fiscal year ended December 31, 1998 Commission File Number 0-18886
HS RESOURCES, INC.
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(Exact name of Registrant as specified in its charter)
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<S> <C>
DELAWARE 94-3036864
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
ONE MARITIME PLAZA, FIFTEENTH FLOOR
SAN FRANCISCO, CA 94111
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(Address of principal executive offices) (Zip Code)
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Registrant's telephone number, including area code: (415) 433-5795
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT
Title of each class of stock
- ------------------------------
Common Stock - $.001 par value New York Stock Exchange
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 March 1, 1999: $99,112,083.
Number of shares of Common Stock outstanding as of the close of business on
March 1, 1999: 18,380,620 after deducting 801,200 shares in treasury.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement of HS Resources, Inc. to be dated on or before
April 30, 1999, 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................................................................ 10
Item 3. Legal Proceedings and Environmental Issues................................ 17
Item 4. Submission of Matters to a Vote of Security Holders....................... 18
Part II.
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.................................................. 19
Item 6. Selected Financial Data................................................... 20
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................................... 21
Item 8. Financial Statements and Supplementary Data............................... 51
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................................... 82
Part III.
Items 10-13. ...................................................................... 82
Part IV.
Item 14. Exhibits.................................................................. 83
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PART I
Item 1. BUSINESS
THE COMPANY
HS Resources, Inc. ("HSR") is a leading U.S. independent energy company engaged
in the development, exploitation, exploration, production, acquisition and
marketing of oil and gas. In 1998 we established a company record in production,
both on an absolute and a per-share basis. We produced 2.6 million barrels of
oil and 57.0 billion cubic feet of gas in 1998, or 72.7 Bcfe (12.1 MMBoe), an
increase of 31% over 1997. Production per share was 3.9 Mcfe (0.65 MBoe),
compared to 3.2 Mcfe (0.54 Boe) in 1997.
The D-J Basin is our core producing region. In December 1997, we acquired from
Amoco Production Company all of Amoco's producing and non-producing oil and gas
properties in the Denver-Julesburg Basin. This strategic acquisition positions
HSR as the leading producer in the D-J Basin with estimated daily production at
year end of more than 182.6 Mcfe (30.4 MBoe).
Effective September 1, 1998, we closed the sale of our Mid-Continent oil and gas
subsidiary, HSRTW, Inc., to Universal Resources Corp., a subsidiary of Questar
Corp., for $157.5 million in cash (the "Mid-Continent Sale"). We repaid a
portion of our bank debt with the proceeds from this sale.
Activities in two other core geographic areas give us a diversified asset base:
the onshore area of the Texas-Louisiana Gulf Coast and, to a lesser extent, the
Northern Rockies. In the Gulf Coast, we control approximately 235,000 gross
undeveloped acres and are conducting an active exploration, exploitation and
development drilling program. We have acquired more than 770 square miles of
Gulf Coast 3-D seismic data and participated in the drilling of 49 wells over
the past three years. In the Northern Rockies, we control approximately 425,000
gross undeveloped acres, primarily in the Williston and Greater Green River
Basins.
At year end, we had an inventory of more than 5,000 development, exploitation
and exploration opportunities, along with more than 900,000 gross undeveloped
acres. The opportunities include development, exploitation, exploration and
infill drilling, recompletion, wellbore deepening and refracturing projects. We
believe that each of our three core geographic areas presents opportunities for
growth in proved reserves and production.
At December 31, 1998, we reported proved reserves of 1,022 Bcfe (170.3 MMBoe),
with estimated pre-tax present value (discounted at 10%) of $531.9 million. Gas
constituted approximately 78% of our reserves and approximately 69% of our
reserves were classified as developed. At December 31, 1998, we operated
approximately 67% of our 4,331 wells. During the twelve months ended December
31, 1998, we generated net cash flow (defined as net income plus geological and
geophysical costs, exploratory and abandonment costs, depletion and
amortization, impairment and gain/loss on sale, income taxes and extraordinary
items) of $72.9 million, with average production for the quarter ended December
31, 1998 of 179.6 MMcfe (29,934 Boe) per day. Net cash provided by operating
activities for the year ended December 31, 1998 was $50.1 million. Effective
December 31, 1998, we changed our method of accounting from the full cost method
to the successful efforts method, and have restated all prior periods based on
this method.
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HSR is a Delaware corporation organized in 1987. Our principal subsidiaries are
Resource Gathering Systems, Inc., which holds 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.
BUSINESS STRATEGY
Our objective is to maximize shareholder value through aggressive growth in our
oil and gas reserves and production. To achieve this objective, we pursue a
strategy of (i) consolidation in core areas, (ii) extensive exploitation of our
property base, (iii) focused exploration in prospective areas, and (iv)
application of advanced technology.
o Consolidation. In December 1997 we acquired Amoco's D-J Basin
properties, capping an effort that spanned several years. By
combining the Amoco properties with our own substantial acreage
and well position, many additional reserves could be "unlocked."
For example, in many instances we owned the right to produce from
formations which were "behind pipe" in an Amoco producing well.
Bringing these reserves into production by recompleting an
existing well typically generates substantially better economics
than those achieved by drilling a new well. In other instances,
Amoco owned the right to produce from formations deeper than
horizons from which HSR was already producing. Deepening an
existing well costs much less than drilling a new well to the
deeper horizon. Without these efficiencies many reserves were
economically "stranded" because drilling a new well could not be
economically justified. The re-aggregation of reserves and value
created by the Amoco acquisition gives us a substantial inventory
of projects with little operational risk, but with attractive
rates of return. In addition, the Amoco properties could be added
to our pre-existing operating structure which made combined
operations more efficient.
o Exploitation. We have more than 5,000 low risk D-J Basin
exploitation projects in our inventory, including such activities
as recompleting new formations in existing wells, re-stimulating
currently producing zones, deepening existing wells to new
formations, and drilling infill and other development locations.
Based on our planned exploitation program alone, without taking
into consideration exploration success, we should be able to
sustain substantial production growth for the next five years. We
anticipate a total 1999 capital budget of $65 to $75 million,
with $20 to $30 million allocated to the D-J Basin. In the D-J
Basin we plan to undertake in 1999 about 100 refracs, 12 new
J-Sand drills, 25 J-Sand deepenings, 20 Dakota deepenings and 20
recompletions.
o Exploration. We have 20 major projects located in the onshore
Gulf Coast region, where we have acquired more than 770 square
miles of 3-D seismic. Initial geological and geophysical work is
nearing completion on several of these projects. We expect to
spend approximately $35 to $45 million in the Gulf Coast during
1999, drilling an anticipated 20 to 40 wells, shooting 115 square
miles of 3-D seismic and acquiring leasehold and option acreage.
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We also have an active 3-D driven exploration project in the D-J
Basin. In addition, our large acreage position in the Northern
Rockies continues to yield significant exploration opportunities.
Joint programs with industry partners are under way on the
Pinedale anticline and we have three high-potential projects in
the Green River Basin in Wyoming.
o Technology. Our highest visibility technology is the use of 3-D
seismic, and in particular 3-D-AVO, 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 1,180 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.
RECENT DEVELOPMENTS
Acquisitions and Divestitures
We are committed to strategic rationalization of assets in each of our core
areas both through advantageous acquisitions and non-core property divestitures.
During 1998 we aggressively pursued these objectives with the most important
transaction being our Mid-Continent Sale in September of 1998. We sold interests
in approximately 1,000 wells (of which we operated 450) located in the Anadarko
and Arkoma basins of Oklahoma and in Texas, with approximately 192 Bcfe (32
MMBoe) of proved reserves as of year-end 1997.
MARKETING AND TRADING
Gas Marketing and Trading
Since the beginning of 1996, the market for HSR's D-J Basin gas has strengthened
due in large part to two factors:
o Excess supply from Wyoming gas producers has declined as a result of
increased demand from and transportation capacity to West Coast markets.
o The Front Range Pipeline of Public Service Company of Colorado has
increased export capacity from the D-J Basin during the vulnerable and
volatile summer months.
For further discussion, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
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Oil Marketing and Trading
We sell substantially all of our oil production under contracts having terms of
one year or less. Oil is sold to many different purchasers at generally market
sensitive rates; as such, we are exposed to price volatility in the sale of our
oil production. Amoco is the most significant purchaser of our oil production,
currently buying 40% of our oil. We believe that there are sufficient crude oil
purchasers in the market so that the loss of any one particular customer would
not have an adverse effect on us.
SECTION 29 TAX CREDITS
We continue to enter into transactions designed to monetize our Section 29 tax
credits for production from tight gas sand reservoirs. Through these
transactions, we have retained a significant portion of the value of the Section
29 tax credits that would otherwise be 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 which specifically cover our transactions. Through these
transactions, we have recognized approximately $8.6 million and $4.4 million of
other gas revenues associated with the tax credits during the years ended
December 31, 1998 and 1997, respectively. We expect to receive in excess of $24
million for tax credits for the period 1999 through 2002. See Item 7
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Disclosure Regarding Forward-Looking Statements."
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 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 received direct access to gas markets but face increased competition
for those markets and must operate under complex transportation tariffs in order
to take advantage of the opportunity to directly market their gas.
Interstate pipelines continue to be regulated by FERC under the Natural Gas Act.
Various state commissions also regulate the rates and services of pipelines
whose operations are purely intrastate in nature. Some state utility
commissions, including the Colorado Public Utilities Commission, now require
that state pipeline and local distribution public utilities offer open access,
non-discriminatory transportation which allows consumers connected to those
systems to contract with producers or other suppliers for gas.
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 also prorate
production to the market demand for oil and gas. Some states have also enacted
statutes establishing maximum rates of production from oil and gas wells.
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Environmental Regulations. Our operations are subject to complex and constantly
changing environmental laws and regulations adopted by federal, state and local
governmental authorities. Compliance with these 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. However, in May 1995, HSR
was named as a respondent by the United States Environmental Protection Agency
("EPA") in an administrative order brought under the Resource Conservation and
Recovery Act ("RCRA") by the EPA against a third-party owner/operator of an
oilfield production water evaporation facility. We do not believe that our share
of reclamation costs will have a material impact on our financial position or
results of operations. See Item 3. "Legal Proceedings--Environmental Issues,"
and Note 11 to Consolidated Financial Statements. Also, the discharge of oil,
gas or other pollutants into the air, soil or water may give rise to significant
liabilities of HSR to the government and/or third parties. Presently, the State
of Colorado Oil and Gas Conservation Commission is considering adopting stricter
policies for the enforcement of environmental rules and regulations. 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. No assurance can be given that
existing environmental laws or regulations, as currently interpreted or as may
be interpreted in the future, or future laws, regulations and policies will not
materially adversely affect our results of operations and financial condition or
that material indemnity claims will not arise against us with respect to
properties we acquire.
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 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. Title
investigation before acquiring undeveloped properties is typically less rigorous
than that conducted prior to drilling, consistent with standard industry
practice.
OPERATIONAL HAZARDS AND INSURANCE
Our operations are subject to the usual hazards incident to the drilling and
production of oil and gas, such as blowouts, cratering, explosions,
uncontrollable flows of oil, gas or well fluids, fires, pollution, releases of
toxic gas and other environmental hazards and risks. These hazards can cause
personal injury and loss of life, severe damage to and destruction of property
and equipment, pollution or environmental damage and suspension of operations.
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We have engaged Aon Risk Services, 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.
EMPLOYEES
At December 31, 1998, we had 275 employees, with 26 located in San Francisco,
California, 95 in Denver, Colorado, 130 in Evans, Colorado, 14 in Tulsa,
Oklahoma, 3 in Oklahoma City, Oklahoma and 7 in Houston, Texas. None of our
employees are subject to a collective bargaining agreement. We consider our
relations with employees to be good. We anticipate that we will hire additional
personnel consistent with our current development drilling programs and other
activities.
OFFICES
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 $ 40,034 December, 2003
Denver, CO 52,749 $ 59,098 June, 2003
Evans, CO 17,985 $ 9,600 February, 2009
Tulsa, OK 6,766 $ 7,795 March, 2002
Houston, TX 5,362 $ 4,692 April, 2000
Oklahoma City, OK 2,248 $ 1,498 September, 1999
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105,658 $122,717
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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, 1998.
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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 36,437 774,920 993,542 165,590 97
Gulf Coast 977 20,078 25,940 4,323 3
Northern Rockies 30 1,912 2,092 349 --
Mid-Continent -- 139 139 23 --
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Total: 37,444 797,049 1,021,713 170,285 100
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Net Net Gross 3-D Seismic
Total Gross Percent Production Production Undeveloped Data
Wells Operated (Mcfe/Day)(1) (Boe/Day)(1) Acreage(2) (square miles)
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D-J Basin 4,281 67 175,416 29,236 250,685 104
Gulf Coast 21 62 4,188 698 234,886 770
Northern Rockies 25 100 -- -- 424,968 313
Mid-Continent 4 -- -- -- 9,330 --
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Total: 4,331 67 179,604 29,934 919,869 1,187
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(1) Calculated for the quarter ended December 31, 1998.
(2) Includes leasehold, option and seismic rights.
Denver-Julesburg Basin
The D-J Basin is located in northeastern Colorado, and for 17 years has been our
primary producing region. Our D-J Basin production and reserves are largely
found in the Codell, Niobrara and J-Sand formations with additional 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 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 1150 - 1350 Btu per cubic foot,
which typically enhances wellhead value.
One of the attractive features of D-J Basin geology is its multi-pay potential.
In a section only 3,500 feet thick, there are at least seven major potentially
productive formations. Three of the formations, the Codell, Niobrara and J-Sand,
are "blanket" zones in the area of our Wattenberg Field holdings, while other
formations, such as the Dakota, D-Sand and shallower Shannon and Sussex, are
more localized.
Wattenberg Field Area. The majority of our D-J Basin properties are concentrated
in the Wattenberg Field area, located approximately 35 miles north of Denver.
Our producing assets in this area produce primarily from the Codell, Niobrara
and J-Sand formations. The Codell and Niobrara formations are found at depths
ranging from 6,400 to 7,700 feet and the J-Sand is found between 7,400 and 7,800
feet. Codell and Niobrara wells produce oil and gas, while J-Sand wells produce
primarily gas. All of the gas from this field has high Btu content, allowing for
extraction of natural gas liquids.
Greater D-J Basin. The Greater D-J Basin is that portion of the D-J Basin
located generally south and east of Wattenberg. Production in the Greater D-J
Basin is generally found in D-Sand and J-Sand channels, and can produce oil, gas
or both. Within the D-Sand and J-Sand, high
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porosities and permeabilities can yield higher flow rates than Wattenberg
wells. D-Sand and J-Sand channels, while not blanket formations, can be prolific
when encountered. The D-Sand and J-Sand are stratigraphically located below the
Codell and Niobrara formations at depths ranging from 6,800 to 7,800 feet.
Gulf Coast
We have established a core geographic area in onshore south Louisiana and the
upper Texas Gulf Coast. Our activities focus on both shallow exploitation and
deeper exploration targets in those areas. Focus areas are Acadia, Jefferson
Davis, Beauregard, Calcasieu, St. Landry and Evangaline Parishes of Louisiana
and Chambers, Jefferson, Ft. Bend and Matagorda Counties in Texas. Wells in the
area target the Frio, Hackberry, Vicksburg, Yegua, Sparta and Wilcox formations
at depths ranging from 3,000 to 13,500 feet. The complex faulted and prolific
salt dome dominated region possesses numerous reservoir targets that, in various
combinations, provide attractive multi-zone drilling prospects from as shallow
as 6,500 feet to deeper than 12,000 feet.
Northern Rockies
We produce in two areas of the Northern Rockies, the Williston and Green River
Basins. We operate wells in two fields in the Daniels County, Montana, portion
of the Williston Basin. These wells produce from the Ratcliffe, McGowan and
Mission Canyon formations at depths ranging from 5,900 to 6,500 feet. We operate
18 wells in the Blue Forest Unit on the Moxa Arch portion of the Green River
Basin in Wyoming. The Blue Forest Unit currently produces from the Frontier and
Muddy formations found at depths of approximately 11,000 feet. Although most of
our oil and gas production in Blue Forest Unit has been sold under the TCW
facility, we have retained development, operating and certain marketing rights.
Denver-Julesburg Basin Projects
We have a significant inventory of investment opportunities in the D-J Basin.
That inventory consists of development drilling on existing spacing units,
behind-pipe recompletions, refrac projects, infill drilling, wellbore
extensions, and exploration leads.
By combining the Amoco properties with those we previously owned, we now own
numerous low-risk development opportunities. Because we owned formations that
were vertically stacked over and under formations previously owned by Amoco, we
can now utilize existing HSR or former Amoco wells to obtain reserves that were
unavailable or uneconomic to either Amoco or us before the Amoco acquisition.
For example, an existing HSR Codell well can be deepened a few hundred feet to
reach the J-Sand or Dakota formations previously owned by Amoco, or an existing
Amoco J-Sand well can be recompleted uphole to produce from the Codell,
Niobrara, Sussex or Shannon formations that we previously owned but were not
economically attractive enough to justify the drilling of a new well. Production
from the various formations can generally be commingled.
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During 1998 we were involved in more than 450 activities in the D-J Basin. Key
activities included refracing the Codell formation in 214 wells, drilling 29 new
J-Sand wells and deepening 41 others, deepening or recompleting the Dakota
formation in 52 wells and recompleting uphole formations in 22 wells.
Gulf Coast Projects
Our onshore Gulf Coast activity is focused in southwest Louisiana and southeast
Texas where we have been developing prospects in 20 major project areas. To
date, we have acquired more than 770 square miles of 3-D seismic data to support
the exploration effort. During 1998, our Gulf Coast program entered the drilling
phase on several projects. We participated in 24 gross wells, 17 of which were
successful. Following are the major drilling activities in which we were
involved in 1998.
Six wells were drilled in the Buhler project, four of which were successful.
Although we have a small interest in the Buhler project, the technological
expertise gained from the program has provided us the basis for developing three
additional project areas in which our working interests range from 25% to 50%.
For example, the North Gillis project in Calcasieu Parish, Louisiana, in which
we have a 37.5% working interest, is a direct offset and analog to the
successful Buhler project. This project targets Hackberry and Yegua sands. We
drilled nine Hackberry wells in North Gillis during 1998, seven of which were
completed as producers. In addition, we drilled one Yegua discovery.
We have a 25% working interest in the Iowa project operated by Sonat
Exploration, Inc. in Jefferson Davis Parish, Louisiana. We participated in
drilling three wells during 1998, one of which was successful. Additionally, we
have a 50% interest in and operate the Welsh project, in which we successfully
drilled and completed one well.
We have a carried working interest in two productive Frio tests which we drilled
on the Devillier project. We also operate and have a 50% working interest in the
Indian Village project. We drilled one successful well there in 1998.
Northern Rockies Projects
Our strategic focus for the Northern Rockies area is to optimize production and
internally generate high potential exploratory projects. To manage risk, we have
entered into agreements with several operators with specific areas of
technological or operational expertise in order to evaluate and exploit certain
of our large acreage positions. By year end, this effort resulted in the
drilling of seven wildcats, four of which are currently being evaluated with
production testing, and the acquisition of more than 24 square miles of 3-D
seismic data.
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We are focusing our efforts on the Greater Green River Basin, one of the most
active and high-potential areas in the Northern Rockies. New geophysical,
drilling and completion technologies appear to be unlocking significant
exploration opportunities targeting over-pressured basin-centered gas.
ACREAGE
Our acreage positions have increased significantly, from approximately 9,000
developed and 37,000 undeveloped net acres as of December 31, 1991, to 457,226
developed and 589,732 undeveloped net acres as of December 31, 1998.
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, 1998.
<TABLE>
<CAPTION>
Developed acres (1) Undeveloped acres (1)
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Area Gross Net Gross Net
- ---- ------- ------- ------- -------
<S> <C> <C> <C> <C>
D-J Basin 563,204 451,227 250,685 217,993
Gulf Coast 15,241 1,556 234,886 99,944
Northern Rockies 13,941 4,443 424,968 265,769
Mid-Continent -- -- 9,330 6,026
------- ------- ------- -------
Total 592,386 457,226 919,869 589,732
======= ======= ======= =======
</TABLE>
(1) Includes acres upon which we own the rights to conduct seismic,
exploration and development activity but not full leasehold rights.
OIL AND GAS RESERVES
In 1998 we engaged Netherland, Sewell & Associates, Inc. to review our estimates
of proved reserves, projected future production and estimated future net
revenues from production of proved reserves as of December 31, 1998. Previously
Netherland, Sewell reviewed only our Mid-Continent reserves. We elected to use
Netherland, Sewell as our sole outside reserve consultant because of Netherland,
Sewell's historic familiarity with the Amoco properties specifically and the D-J
Basin generally, and its ability to handle electronically our large base of
data. Netherland, Sewell'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 determining the estimates of the reserve quantities
that are economically recoverable, we used selling prices (without consideration
of hedging benefits) and estimated development and production costs which were
in effect as of December 31, 1998. 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, 1998, derived from our reserve reports. The present value
(discounted at 10%) of estimated future net revenues before income taxes shown
in the table is not intended to represent the current market value of the
estimated oil and gas reserves owned by HSR. In the aggregate, Netherland,
Sewell reviewed proved properties constituting 88% of our pre-tax present value
of total proved reserves.
13
<PAGE> 14
<TABLE>
<CAPTION>
Net proved reserves
as of December 31, 1998
-----------------------
Developed Undeveloped Total
--------- ----------- ---------
<S> <C> <C> <C>
Oil and condensate (MBbl) 23,558 13,886 37,444
Gas (MMcf) 561,410 235,639 797,049
Equivalent Gas (MMcfe) 702,758 318,955 1,021,713
Equivalent barrels (MBoe) 117,126 53,159 170,285
Present value of estimated
future net revenues before income
taxes (discounted at 10%)
(in thousands) $496,235 $ 35,670 $531,905
</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 an 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, 1998, were $9.99 per Bbl of oil and
$1.94 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 "Risk Factors."
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.
14
<PAGE> 15
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 that on a net interest basis), while reserves reported herein are net to
HSR.
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
comprised a large portion of our 1998 activities.
<TABLE>
<CAPTION>
Year ended December 31,
-----------------------
1998 1997 1996
---- ---- -----
<S> <C> <C> <C>
Development:
Productive 59.4 65.3 116.7
Non-productive 0.0 5.3 0.0
---- ---- -----
Total 59.4 70.6 116.7
---- ---- -----
Exploratory:
Productive 7.3 14.2 3.5
Non-productive 7.1 9.7 0.0
---- ---- -----
Total 14.4 23.9 3.5
---- ---- -----
Total wells 73.8 94.5 120.2
==== ==== =====
</TABLE>
PRODUCTIVE OIL AND GAS WELLS
As of December 31, 1998, 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 1,771 460 2,231 1,710.0 106.8 1,816.8
Gas 1,120 34 1,154 1,007.8 9.0 1,016.8
----- --- ----- ------- ----- -------
Total 2,891 494 3,385 2,717.8 115.8 2,833.6
===== === ===== ======= ===== =======
</TABLE>
(1) We also have overriding royalty interests in 946 gross (51.7 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.
15
<PAGE> 16
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 (dollars in thousands).
<TABLE>
<CAPTION>
Year ended December 31,
-----------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Acquisition costs:
Unproved properties $ 15,414 $130,169 $ 34,569
Proved properties 12,615 226,458 348,492
Exploration costs 10,747 12,856 2,100
Development costs 78,736 44,375 36,177
-------- -------- --------
Total costs incurred $117,512 $413,858 $421,338
======== ======== ========
</TABLE>
PRODUCTION
The following table sets forth our oil and gas production data during the
periods indicated.
<TABLE>
<CAPTION>
Year ended December 31,
-----------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Net production:
Oil and condensate (MBbl) 2,630 2,400 1,923
Gas (MMcf) 56,969 41,125 34,163
Equivalent gas (MMcfe) 72,750 55,524 45,702
Equivalent barrels (MBoe) 12,125 9,254 7,617
Average net daily production(1):
Oil and condensate (Bbl) 6,378 6,679 5,255
Gas (Mcf) 141,336 117,589 93,342
Equivalent gas (Mcfe) 179,604 157,663 124,872
Equivalent barrels (Boe) 29,934 26,277 20,812
Average sales price per unit:
Oil and condensate ($/Bbl) $ 14.58 $ 19.71 $ 20.90
Gas ($/Mcf) $ 1.96 $ 2.19 $ 1.96
Lease operating expense ($/Mcfe) $ 0.42 $ 0.45 $ 0.39
Lease operating expense ($/Boe) $ 2.51 $ 2.69 $ 2.32
</TABLE>
(1) Average daily production for 1998 and 1997 was calculated for the quarter
ended December 31, as the results are believed to be more indicative of
current performance.
16
<PAGE> 17
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. JW alleges that the defendants damaged JW's
leasehold rights in certain oil and gas leases in Potter County, Texas. The
complaint alleges that HSR and HSRTW, Inc., as the owner and/or operator of deep
rights in these leases, damaged the plaintiff's shallow rights in the same lands
by failing to cement the shallow zones during the drilling of wells to the deep
formations. HSR and HSRTW have denied each claim made by the plaintiff and
believe that they have substantial scientific and legal defenses to each claim
and intend to vigorously defend against them. Although it is not possible to
predict the outcome of this matter at trial, we believe that the litigation will
not have a material adverse effect on our results of operations or financial
condition.
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 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-operator respondents are working together
with the EPA to develop plans and characterization studies, and have caused the
facility to be permanently closed.
We utilized this facility in past years to dispose of our production and
flowback water. During the period of its use, we believed that the facility was
operating in compliance with all applicable legal requirements and, along with
other oil and gas operators, paid a fee to WCWDI for using this disposal
facility. There were a number of other significant contributors to the facility
during the period reviewed by the EPA (1988 through 1994) and additional
contributors during the period from 1977, when it was constructed, through 1988.
HSR and the major oil company were named because they were deemed the major
contributors of waste volumes to the facility for the period reviewed by the
EPA. Certain other contributors are participating in their share of the
reclamation costs.
Based on our current knowledge and our expectation of proportionate
reimbursement from other parties who utilized the facility, we do not believe
that our share of the reclamation costs will have a material impact on our
financial condition or results of operations. By agreement with other
contributing parties, we are currently paying approximately 50% of the costs
associated
17
<PAGE> 18
with the project, but after recovery from additional liable parties, our
percentage share of overall costs may be reduced to as low as 40%. We have spent
approximately $1.1 million on our behalf to date on the project. Our share of
total costs associated with the project are currently estimated to be
approximately $1.3 million. The remaining estimated liability has been accrued
at year end.
Recent data regarding site conditions indicate a potentially more significant
contamination problem in one portion of the site. This problem is the apparent
result of disposal of non-oil field wastes by third parties a number of years
prior to our involvement as an oil field waste disposal customer of this
facility. This recent data gives rise to both the possibility of a defense of
non-liability for the divisible harm caused by wastes of third parties and
greater uncertainty regarding the total costs of study and clean-up for which we
are potentially liable. For these reasons, we are not able at this time to
determine our probable share, if any, of future response costs for these non-oil
field wastes.
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.
Operations on several drillsites likely have, and operations on several others
may have 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. The Corps issued
a routine cease and desist order to HSR prohibiting any further unpermitted
wetlands disturbance, but not interfering with continuation of production or
other operations. We cannot predict whether any fines will be issued in
connection with the violations; however, we do not believe the outcome of this
proceeding will have a material adverse impact on HSR. See Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Disclosure Regarding Forward-Looking Statements."
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
18
<PAGE> 19
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
HSR's common stock (New York Stock Exchange symbol "HSE") is traded publicly on
the NYSE. The following table presents the high and low sales prices reported by
the NYSE for the periods indicated. These prices do not include retail markups,
markdowns or commissions.
<TABLE>
<CAPTION>
Quarter ended High Low
- ------------------ -------- ------
<S> <C> <C>
March 31, 1996 13 1/8 9 1/4
June 30, 1996 13 1/4 10 3/8
September 30, 1996 14 1/8 11 3/4
December 31, 1996 17 5/8 12 7/8
March 31, 1997 18 3/8 11 1/2
June 30, 1997 15 10 7/8
September 30, 1997 17 7/8 13 3/16
December 31, 1997 18 3/4 12 5/8
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
</TABLE>
As of December 31, 1998, there were 577 holders of record of the 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.
19
<PAGE> 20
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>
(In thousands, except per share amounts and average prices)
For the years ended December 31,
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Statement of Operations Data
Revenues
Oil and gas sales $ 150,087 $ 137,251 $ 107,281 $ 53,394 $ 58,827
Trading and transportation 54,144 90,062 46,373 -- --
Other revenues 9,965 6,392 3,302 1,946 1,574
---------- ---------- ---------- ---------- ----------
Total revenues 214,196 233,705 156,956 55,340 60,401
---------- ---------- ---------- ---------- ----------
Expenses
Production taxes 10,422 9,703 8,195 4,050 5,134
Lease operating 30,410 24,848 17,692 9,936 8,310
Cost of trading and transportation 50,451 88,402 45,699 -- --
Depreciation, depletion and amortization 61,223 45,757 36,600 24,577 24,266
Exploratory and abandonment 15,420 13,438 5,927 7,202 5,071
Geological and geophysical 14,308 17,049 4,262 3,509 4,991
Impairment and loss (gain) on sale of
oil and gas properties 11,986 15,710 2,909 (165) --
General and administrative 8,061 11,550 8,497 5,613 6,334
Interest 41,990 32,297 23,594 10,806 7,887
---------- ---------- ---------- ---------- ----------
Total expenses 244,271 258,754 153,375 65,528 61,993
---------- ---------- ---------- ---------- ----------
Loss (income) before provision for
income taxes (30,075) (25,049) 3,581 (10,188) (1,592)
Benefit (provision) for income taxes 11,459 9,544 (1,364) 3,882 607
---------- ---------- ---------- ---------- ----------
Net (loss) income $ (18,616) $ (15,505) $ 2,217 $ (6,306) $ (985)
---------- ---------- ---------- ---------- ----------
Diluted (loss) earnings per share $ (1.00) $ (0.91) $ 0.15 $ (0.58) $ (0.09)
---------- ---------- ---------- ---------- ----------
Weighted average number of common shares
outstanding assuming dilution 18,609 17,119 14,552 10,893 10,918
========== ========== ========== ========== ==========
Balance Sheet Data
Working (deficiency) capital $ (18,899) $ (8,329) $ 13,749 $ (16,115) $ (2,384)
Oil and gas properties, net 748,934 877,467 613,119 254,046 227,882
Total assets 832,439 956,306 695,644 277,324 254,943
Long-term debt, net of current portion 534,917 636,699 398,563 125,537 103,478
Deferred income taxes 44,138 61,933 72,487 15,406 19,288
Stockholders' equity 152,861 173,477 169,424 102,606 109,375
Operating Data
Average sales price per barrel of oil $ 14.58 $ 19.71 $ 20.90 $ 16.52 $ 14.83
Average sales price per thousand
cubic feet of gas $ 1.96 $ 2.19 $ 1.96 $ 1.30 $ 1.70
Production
Oil (Bbl) 2,630 2,400 1,923 1,582 1,664
Gas (Mcf) 56,969 41,125 34,163 21,049 20,108
Mcfe 72,750 55,524 45,702 30,540 30,090
Boe 12,125 9,254 7,617 5,090 5,015
Net cash provided by
operating activities $ 50,083 $ 58,876 $ 38,549 $ 18,343 $ 24,038
</TABLE>
20
<PAGE> 21
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL We have pursued a strategy centered around consolidation 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.
Our success in consolidating in the D-J Basin culminated in 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 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.
The Amoco acquisition and related consolidation in the D-J Basin, coupled with
our exploration successes in the Gulf Coast, have materially increased the
number of low-risk, high-return projects available to us. However, the Amoco
acquisition required us to borrow funds, significantly increasing our leverage
ratios. As a result, 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. 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 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 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 the past several
months, United States natural gas prices and international crude oil prices have
declined precipitously, resulting in significant changes to the operating and
financial margins of oil and gas producers. The recent downturn in oil prices is
attributable to a global oversupply of crude oil resulting from the economic
difficulties in Asia, Russia and elsewhere, high levels of production by certain
OPEC and non-OPEC producers and warm weather in the United States. As a result
of these factors, the HSR weighted average price realized per barrel of oil,
excluding hedging benefits, in 1998 was $12.99 compared to $19.57 for 1997.
Natural gas prices per Mcf, excluding hedging benefits, were $1.88 in 1998,
compared to $2.27 in 1997, primarily due to above-normal winter temperatures in
both 1997 and 1998, resulting in excess supplies of gas in winter storage.
Additionally, low oil prices also have had a depressing effect on the price of
liquids recovered from natural gas. Thus, the recent low oil price environment
has further diminished the overall price received for our gas production.
21
<PAGE> 22
At December 31, 1998, approximately 82% of our proved producing reserves
consisted of gas, of which 98% 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, which remains the case during the lower demand
summer months (generally April through October). More recently, however, as a
result of increased pipeline capacity in 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 recent months two applications have been approved to build pipelines between
the Colorado Front Range market area and Wyoming. A subsidiary of KN Energy,
Inc. ("KN") has been granted authority to build a 250 MMcfd capacity pipeline,
while PSCO and CIG, through a jointly owned affiliate, recently began operating
a newly expanded 270 MMcfd capacity line. This line operates independently and
not as part of PSCO's local distribution system. Construction has not commenced
on the KN line, and it is uncertain whether this line will be built in the near
future. The PSCO line will eliminate some portion of the 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.
In recent months, gas prices nationwide have been relatively low due to large
inventories and modest demand. We believe this weakness in gas prices is a
seasonal variation reflecting above-normal winter temperatures in 1997 and 1998
and does not necessarily indicate a significant long-term change in overall
average gas pricing. However, we cannot predict the future trends in gas prices.
The uncertainty concerning the price of oil and gas remains a dominant and
unpredictable factor in our profitability.
CHANGE IN ACCOUNTING METHOD During the fourth quarter of 1998, we elected to
convert from the full cost method to the successful efforts method of accounting
for our investments in oil and gas properties. We believe that the successful
efforts method of accounting is preferable, as it more accurately presents the
results of our exploration and development activities. Accordingly, the December
31, 1998 consolidated balance sheets, consolidated statements of operations and
consolidated statements of cash flows included in this Form 10-K have been
restated to conform with successful efforts accounting. The cumulative effect of
this change, net of income taxes, was to reduce December 31, 1997 retained
earnings by $50.1 million. For the statements of operations for the years ended
December 31, 1997 and 1996, the effect of the accounting change was to decrease
net income by $26.8 million ($1.57 per diluted share) and $6.7 million ($0.46
per diluted share), respectively.
22
<PAGE> 23
RESULTS OF OPERATIONS During 1998 we increased our drilling and development
activities to exploit the larger number of development opportunities in the D-J
Basin resulting from the Amoco acquisition. We also continued our exploitation
and exploration activities in the Gulf Coast region. At December 31, 1998 we
owned interests in more than 4,300 producing wells (of which we operated more
than 2,880) compared to more than 5,300 wells (of which we operated more than
3,300) at December 31, 1997. The Mid-Continent sale, which closed on September
1, 1998, reduced our well inventory by more than 1,000 producing wells. Our
results of operations have been significantly affected by the Amoco acquisition,
by our drilling program and by fluctuations in oil and gas prices. Future
results will be significantly affected by our exploration, exploitation and
development activities.
Comparative operating results by business segment, consolidated other income,
expenses and income taxes are presented below. Segment operating revenues, costs
and expenses are before intersegment eliminations.
23
<PAGE> 24
COMPARISON OF YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
D-J BASIN
OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES)
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Production:
Oil (Bbl) 2,382 1,957 1,614
Gas (Mcf) 48,628 24,871 23,398
Mcfe 62,920 36,612 33,082
Boe 10,487 6,102 5,514
Prices:
Average realized oil price ($/Bbl) $ 14.78 $ 19.78 $ 21.34
Average realized gas price ($/Mcf) $ 1.96 $ 2.15 $ 1.93
Operating Revenues:
Oil and gas sales $130,601 $ 92,067 $ 79,621
Other gas revenues 8,658 4,290 2,650
-------- -------- --------
139,259 96,357 82,271
-------- -------- --------
Operating Costs and Expenses:
Production taxes 9,120 6,376 6,044
Lease operating 25,938 17,273 13,324
Depreciation, depletion
and amortization 50,735 23,147 25,154
Exploratory and abandonment 1,188 1,582 933
Geological and geophysical 1,892 835 1,165
Impairment and (gain) loss on sale
of oil and gas properties (1,152) -- 201
-------- -------- --------
87,721 49,213 46,821
-------- -------- --------
Operating Income $ 51,538 $ 47,144 $ 35,450
======== ======== ========
</TABLE>
GENERAL We have been active in the D-J Basin for 17 years. Over the past three
years we have further consolidated our position as a result of the acquisition
in June 1996 of all of the D-J Basin properties of Basin Exploration, Inc. and
the December 1997 Amoco acquisition. During 1998 a substantial exploitation
program was undertaken consisting of more than 450 separate activities.
24
<PAGE> 25
OIL AND GAS REVENUES Over the past three years, our D-J Basin oil and gas
production has increased dramatically. The production increases were primarily
the result of additional production from properties acquired in the 1996
acquisition from Basin Exploration and the Amoco acquisition, as well as 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
have also increased during the same period.
PRODUCTION EXPENSES Lease operating expense ("LOE") increased due to an increase
in the number of producing wells. LOE per Mcfe was $0.41, $0.47 and $0.40
($2.47, $2.83 and $2.42 per Boe) for 1998, 1997 and 1996, respectively. The
decrease per Mcfe from 1997 to 1998 was due to increased efficiencies in
combining the assets acquired in the Amoco acquisition with our previously
existing asset base. The increase per Mcfe from 1996 to 1997 was the result of a
different mix of wells in 1997, including wells with historically higher
operating costs which were obtained as a result of the Basin acquisition, and
new wells drilled by us. Production taxes increased in 1998 due to increased
production and were partially offset by decreased prices. In 1997, production
taxes increased due to increases in production and gas prices, and were
partially offset by an adjustment for prior year severance tax refunds.
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 1996 to 1997 due to a decrease in the depletion
rate. The weighted average depletion rate per Mcfe for the D-J Basin was $0.80,
$0.62 and $0.75 ($4.81, $3.74 and $4.51 per Boe) for the years ended December
31, 1998, 1997 and 1996 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. In 1998, we incurred $0.9 million
for exploratory dry hole and P&A costs, $0.2 million for delay rentals and
expired acreage and $0.1 million for overhead costs directly attributable to
exploratory activity. In 1997, we incurred $1.0 million for exploratory dry hole
and P&A costs, $0.5 million for delay rentals and expired acreage and $0.1
million for overhead costs. In 1996, we incurred $0.4 million for exploratory
and P&A costs and $0.5 million for delay rentals and expired acreage.
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 $1.4 million,
$0.5 million and $0.7 million in seismic costs for the years ended 1998, 1997
and 1996, respectively. The remaining G&G costs of $0.5 million, $0.3 million
and $0.5 million relate to overhead costs directly attributable to G&G
activity. The
25
<PAGE> 26
increase in 1998 compared to the prior year relates to an increase in 3-D
seismic activity in the Greater D-J Basin area.
IMPAIRMENT AND GAIN ON SALE OF OIL AND GAS PROPERTIES In 1998, we recorded a
gain on the sale of wells sold primarily in the Yuma County area of the D-J
Basin. We sold 93 wells for $2.9 million in cash.
GULF COAST
OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES)
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Production:
Oil (Bbl) 30 22 --
Gas (Mcf) 883 478 --
Mcfe 1,061 607 --
Boe 177 101 --
Prices:
Average realized oil price ($/Bbl) $ 11.99 $ 19.05 $ --
Average realized gas price ($/Mcf) $ 2.25 $ 2.81 $ --
Operating Revenues:
Oil and gas sales $ 2,344 $ 1,754 $ --
Other gas revenues -- -- --
-------- -------- --------
2,344 1,754 --
-------- -------- --------
Operating Costs and Expenses:
Production taxes 131 103 --
Lease operating 160 20 --
Depreciation, depletion
and amortization 510 274 --
Exploratory and abandonment 9,127 6,570 497
Geological and geophysical 10,826 15,052 2,555
Impairment and loss on sale
of oil and gas properties 1,061 -- --
-------- -------- --------
21,815 22,019 3,052
-------- -------- --------
Operating Loss $(19,471) $(20,265) $ (3,052)
======== ======== ========
</TABLE>
GENERAL Over the past three years, the majority of our Gulf Coast activities
have focused on the acquisition, processing and interpretation of 3-D seismic
information and the acquisition of leasehold interests. During 1999 and
thereafter we expect to materially increase our level of Gulf
26
<PAGE> 27
Coast drilling activities on prospects which we have identified through our
extensive 3-D seismic programs.
OIL AND GAS REVENUES Oil and gas revenues remained relatively flat between 1997
and 1998. The increase in production was partially offset by a decrease in
prices. We drilled a total of 24 gross (6.7 net) wells in 1998; however, the
impact of this activity will not be reflected until 1999 because the majority of
the wells were drilled late in the year or the wells were waiting on completion
or pipeline hookup at year-end.
EXPLORATORY AND ABANDONMENT COSTS The largest components of exploratory and
abandonment costs in 1998 included the following: $5.8 million for expired
acreage in both our SouthTech and other 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 $9.4 million
and $13.8 million in 1998 and 1997, respectively, for seismic permits and
processing costs in the Gulf Coast. The remaining G&G of $1.5 million and $1.2
million relates to overhead costs directly attributable to G&G activity.
IMPAIRMENT AND LOSS ON SALE OF OIL AND GAS PROPERTIES In 1998, we recorded a
loss on the sale of two wells. The wells were conveyed in a non-cash transaction
to a third party purchaser which assumed liability for P&A costs.
27
<PAGE> 28
MID-CONTINENT AND OTHER
OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES)
<TABLE>
<CAPTION>
1998(1) 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Production:
Oil (Bbl) 218 421 309
Gas (Mcf) 7,459 15,777 10,765
Mcfe 8,768 18,305 12,624
Boe 1,461 3,051 2,104
Prices:
Average realized oil price ($/Bbl) $ 12.80 $ 19.44 $ 18.60
Average realized gas price ($/Mcf) $ 1.92 $ 2.23 $ 2.03
Operating Revenues:
Oil and gas sales $ 16,983 $ 43,430 $ 27,660
Other gas revenues 62 159 70
-------- -------- --------
17,045 43,589 27,730
-------- -------- --------
Operating Costs and Expenses:
Production taxes 1,172 3,224 2,151
Lease operating 4,311 7,555 4,368
Depreciation, depletion
and amortization 8,042 20,290 9,816
Exploratory and abandonment 5,104 5,287 4,496
Geological and geophysical 1,591 1,162 542
Impairment and loss on sale
of oil and gas properties 12,077 15,709 2,708
-------- -------- --------
32,297 53,227 24,081
-------- -------- --------
Operating (Loss) Income $(15,252) $ (9,638) $ 3,649
======== ======== ========
</TABLE>
- ------------
(1) Results through date of sale, September 1, 1998.
GENERAL Information for this segment includes activity for both the
Mid-Continent and Northern Rockies areas. Activity in the Mid-Continent began on
June 17, 1996 as a result of the merger with Tide West Oil Company. 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 six 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 on our acreage by third party
operators.
28
<PAGE> 29
OIL AND GAS REVENUES The decrease in oil and gas revenues from 1997 to 1998 in
the Mid-Continent is due to a decrease in production as a result of a full year
of activity in 1997 versus eight months of activity in 1998, a decrease in
prices from 1997 to 1998 and divestitures of certain Mid-Continent properties in
the third and fourth quarters of 1997. The increase in revenue from 1996 to 1997
was due to increased prices and production as a result of a full year of
activity in 1997 versus approximately six months of activity in 1996.
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 and
increased in 1997 compared to 1996 as a result of the fluctuation in revenues
discussed above.
DEPRECIATION, DEPLETION AND AMORTIZATION DD&A decreased in 1998 compared to 1997
due to a decrease in production and a decrease in the depletion rate. DD&A
increased in 1997 compared to 1996 due to an increase in production and an
increase in the depletion rate. The weighted average depletion rate per Mcfe for
the Mid-Continent was $0.92, $1.12 and $0.82 ($5.52, $6.70 and $4.89 per Boe)
for the years ended December 31, 1998, 1997 and 1996, respectively.
EXPLORATORY AND ABANDONMENT COSTS The majority of exploratory and abandonment
costs for 1998, 1997 and 1996 represent costs incurred for expired acreage,
delay rentals and capitalized interest for projects in the Northern Rockies.
GEOLOGICAL AND GEOPHYSICAL COSTS The majority of the costs incurred in 1998,
1997 and 1996 relate to G&G activity on projects in the Northern Rockies.
IMPAIRMENT AND LOSS ON SALE OF OIL AND GAS PROPERTIES In 1998, 1997 and 1996,
we recorded impairments of $5.0 million, $1.6 million and $2.7 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.
29
<PAGE> 30
TRADING AND TRANSPORTATION (IN THOUSANDS)
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Operating Revenues:
Trading and transportation $142,374 $148,994 $ 60,718
Operating Costs and Expenses:
Cost of trading and transportation 136,245 146,652 59,507
Depreciation and amortization 416 382 187
-------- -------- --------
136,661 147,034 59,694
-------- -------- --------
Operating Income $ 5,713 $ 1,960 $ 1,024
======== ======== ========
</TABLE>
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 1998 compared to prior periods 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.
OTHER INCOME AND EXPENSES (IN THOUSANDS)
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Interest income and other $ 1,405 $ 1,943 $ 582
General and administrative $ 8,061 $ 11,550 $ 8,497
Interest $ 41,990 $ 32,297 $ 23,594
Depreciation $ 1,520 $ 1,664 $ 1,443
</TABLE>
INTEREST INCOME AND OTHER INCOME Interest and other income decreased from 1997
to 1998 due to a decrease in funds available for short-term investing. From 1996
to 1997 interest income increased due to interest received for prior year
severance tax refunds, short-term investing of our available funds, and income
recorded on our interest in a limited partnership.
GENERAL AND ADMINISTRATIVE EXPENSES General and administrative expenses ("G&A")
reflect costs incurred, net of administrative costs directly attributable to
drilling and well operations (which costs are included in LOE). G&A costs
directly related to geological and geophysical activities and exploratory
activities are included in geological and geophysical costs and
30
<PAGE> 31
exploratory costs. G&A per Mcfe was $0.11, $0.21 and $0.19 ($0.66, $1.25 and
$1.12 per Boe) in 1998, 1997 and 1996, respectively. On both an absolute and an
Mcfe basis, G&A decreased from 1997 to 1998 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. From 1996 to 1997, G&A increased on
both an absolute and an Mcfe basis due to increased administrative costs
resulting from the 1996 merger with Tide West Oil Company and the greater number
of Tide West employees, as well as the addition of personnel and facilities
throughout 1997 which were required in order to accomplish our acquisition,
drilling and exploration objectives.
INTEREST EXPENSE 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. Interest expense also increased from 1996 to 1997
due to amounts borrowed to fund the Basin acquisition and the merger with Tide
West.
INCOME TAXES (IN THOUSANDS)
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Current benefit (provision) $ (5,300) $ (900) $ (300)
Deferred benefit (provision) 16,759 10,444 (1,064)
-------- -------- --------
Benefit (provision) for taxes $ 11,459 $ 9,544 $ (1,364)
======== ======== ========
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 1998, 1997 and 1996. Due to significant
intangible drilling costs, which are deductible for income tax purposes,
substantially all of our tax provision in 1997 and 1996 is deferred. In 1998,
the current provision is attributable to taxes owed in connection with the sale
of our Mid-Continent properties.
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<PAGE> 32
LIQUIDITY AND CAPITAL RESOURCES
Financing Sources
At December 31, 1998, our overall debt level was significantly lower than at
December 31, 1997 as a result of the repayment of $152 million of bank debt from
the proceeds of the Mid-Continent sale. Bank debt was further reduced in
December 1998 by the repayment of $78 million from the net proceeds of the sale
of $85 million Series B 9 1/4% Senior Subordinated Notes due 2006. We believe
that our current level of debt and leverage is manageable under expected
production and pricing levels, since our debt is supported by stable, long-lived
producing reserves and by our hedging programs, with short-term product prices
partially hedged at favorable prices. 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 price declines. 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
are evaluating a wide range of future financing alternatives and are not
committed to any particular course. In undertaking any future financing
transactions, we intend to 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 offering of the Series B 9 1/4% Notes was undertaken in order to replace
with fixed rate term debt a portion of our outstanding indebtedness under our
revolving senior bank credit facility with The Chase Manhattan Bank. As a
result, on December 10, 1998 the Chase facility was amended to reduce the
borrowing base to $280 million. Effective December 31, 1998, we entered into the
seventh amendment to the Chase facility to modify certain covenants under the
facility as a result of our conversion to the successful efforts method of
accounting. 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, 1998, $230 million was outstanding
under the Chase facility.
We also have maintained an arrangement with a Trust Company of the West-related
entity covering a $90 million non-recourse, volumetric overriding royalty
facility of which approximately $80 million has not been utilized. The TCW
facility has been available for a variety of corporate purposes, including
acquisitions of new properties, exploration and development drilling and
monetization of existing properties. TCW has notified us that the unused portion
of the TCW facility might not be extended beyond March 31, 1999.
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<PAGE> 33
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, 1998, we incurred total costs for exploration, development,
leasehold, exploratory and abandonment and geological and geophysical activities
of $101.2 million, including costs on our Mid-Continent properties, exclusive of
capitalized interest. We estimate that such expenditures for 1999 will be
approximately $65 to $75 million, assuming stable product prices for the 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 $64.4 million for the year ended
December 31, 1998 for costs to drill, recomplete and refrac our D-J Basin
properties, and anticipate allocating $20 to $30 million to the D-J Basin for
1999.
Another component of our capital program has been to develop exploitation and
exploration prospects in the onshore portion of the Gulf Coast and in the
Mid-Continent. For the year ended December 31, 1998, we incurred total
expenditures of $24.3 million for seismic, leasehold, drilling and overhead
costs in the Gulf Coast, including approximately $19.4 million of expenditures
under our SouthTech joint venture and $4.9 million on our other Gulf Coast
projects. We also spent $9.0 million in the Mid-Continent. We anticipate
allocating $35 to $45 million to the Gulf Coast projects for 1999 for
exploration and development activities including land and seismic.
Activities in our Northern Rockies area are designed to utilize our extensive
acreage position as a vehicle for generating capital expenditures by third party
operators on our acreage. For the year ended December 31, 1998 approximately
$8.0 million was spent or committed to by others to test plays and concepts on
our acreage, while we retained significant positions for exploiting successful
discoveries.
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<PAGE> 34
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
Net cash provided by operating activities for the year ended December 31, 1998
was $50.1 million, down from $58.9 million for the same period in 1997. 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, to the maximum extent possible we hedge certain of
our production back to the wellhead. 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 change the 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).
Our general strategy is to hedge price and location risk with swap, collar,
floor and ceiling arrangements. 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 basis to our producing regions.
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<PAGE> 35
As of December 31, 1998, we hold hedge swap positions as follows:
<TABLE>
<CAPTION>
Average Daily
Volume Settlement Price
Time Period (MMBtu) Location (per MMBtu)
- ----------- ------------- ---------- -----------
<S> <C> <C> <C>
January 99 - March 99 25,000 PEPL $ 2.40
January 99 - March 99 50,000 PEPL $ 2.45
April 99 - October 99 50,000 CIG $ 1.90
April 99 - October 99 50,000 NW $ 1.735
</TABLE>
We have hedged our expected oil production as follows:
<TABLE>
<CAPTION>
Monthly Hedged Settlement Price
Time Period Volume (Bbl) Location (per Bbl)
- ----------- ------------ -------- ---------
<S> <C> <C> <C>
January 99 - December 99 30,400 NYMEX $ 16.45
January 99 - December 99 60,800 NYMEX $ 15.95
</TABLE>
Additionally, with respect to the hedging of third party gas, we have hedged
20.1 Bcf from January 1999 through June 2000 with offsetting physical positions
at settlement prices which are based upon NYMEX future prices of other published
indices.
We routinely buy and sell options or forward contracts as part of our overall
hedging strategy. Currently, we have no open 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.
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<PAGE> 36
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. As of December 31, 1998, all
material open positions were balanced with an offsetting position. During the
year ended December 31, 1998, gains of $2.8 million were recognized in
connection with these activities and are included in "trading and transportation
revenues."
Credit Risk
While notional amounts are used to express the volume of various derivative
financial instruments, the amounts potentially subject to credit risk in the
event of nonperformance by the third parties are substantially smaller.
Counterparties to the swap, collar, floor and ceiling arrangements discussed
above are generally investment grade institutions. Accordingly, we do not
anticipate any material impact to our financial position or results of
operations as a result of nonperformance by the third parties to financial
instruments related to hedging activities or trading activities.
Interest Rate Swaps
During the fourth quarter of 1998, we entered into an interest rate exchange
agreement with a financial institution to hedge the interest rate on $80 million
of our borrowings at 5.86% through December 15, 2006. Under the terms of the
agreement, the difference between the fixed rate of 5.86% and the one-month
LIBOR rate is received or paid by us. As part of this hedging agreement, we
cancelled or offset our previous hedging agreements. Market risk related to
borrowings from a one percent change in interest rates would result in an
approximate $1.5 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 Swap
On February 25, 1999, we entered into a total return equity swap with a
financial institution, whereby the financial institution acquired approximately
730,000 shares of our common stock from another investor. Under the terms of the
swap agreement, 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. At the earlier
of July 1, 2000 or the termination of the swap agreement we will receive any
increase in the market value of the shares (as defined) above the $6.0625
purchase price, or will pay for any loss; however, we may cover any losses by
issuing common stock to the financial institution if we choose to do so. We will
also pay certain commissions and finance costs.
Contingencies
In May 1995, we, along with a major oil company, were named as respondents by
the EPA in an administrative order brought under RCRA by the EPA against the
owner/operator of an oilfield production water evaporation facility. Based on
our evaluation of the above matters, and after consideration of
36
<PAGE> 37
reserves established, we believe the resolution of this matter will not have a
material adverse effect on our financial condition or results of operations. See
Item 3. "Legal Proceedings and Environmental Issues" and Note 11 of the Notes to
Consolidated Financial Statements.
Year 2000
We have undertaken and are continuing our analysis and corrective measures to
address the Year 2000 problem. The Year 2000 problem results from computer
programs that were written utilizing two digits rather than four to define an
applicable year. These programs are unable to distinguish between years in
different centuries, eg. 1910 and 2010 appear to be the same year. Therefore,
our computer equipment, software, and devices with embedded technology could
encounter problems beginning on January 1, 2000. This could result in a system
failure or miscalculations causing disruptions of field and/or office
operations, as well as disruptions in the business operations of our vendors and
customers.
In addressing the problem, we have considered both our information technology
("IT") systems and non-IT systems. IT systems include computer hardware and
software systems as well as telephone and other communications systems. Non-IT
systems include fax machines, copiers, monitors for field operations, and other
miscellaneous systems. Both IT and non-IT systems may contain embedded
technology, which is also subject to the Year 2000 problem. However, correcting
problems in non-IT systems poses the greatest challenge.
Based upon our assessment and corrective efforts to date, we believe that most
of our IT systems are currently Year 2000 compliant. Those systems that remain
non-compliant generally require only upgrading or installation of software
correction packages which have been identified and which are available. Few, if
any, of our IT systems will require replacement. We currently expect to have
substantially all of our IT systems in compliance by June 30, 1999.
Virtually all of our non-IT systems are provided by third parties. We have
reviewed our critical path non-IT systems in the D-J Basin. The primary
mechanisms of concern to us were the well control units that electronically
control production from each of the wells. Many of these contain embedded chip
technology. Based on written representations of the manufacturers, however, we
believe that these systems are Year 2000 compliant. We have not yet assessed our
non-IT office systems, such as fax machines and copiers. We have scheduled
assessment of these systems during the second quarter of 1999. We will contact
the third-party providers or manufacturers of these non-IT office systems to
determine if any of these require remediation or replacement.
We are in the process of identifying our most significant third-party vendors
and service providers to determine their state of readiness regarding the Year
2000 problem as it relates to us. Our key third-party providers include
gatherers, processors and pipelines, oil and gas purchasers, our banks, the New
York Stock Exchange, Harris Trust & Savings Bank (our transfer agent), the
property managers of our leased office space, equipment suppliers, major joint
venture partners and others. We are contacting third-party providers either
verbally or in writing and reviewing their public disclosures concerning the
Year 2000 problem in an effort to determine whether we
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<PAGE> 38
are vulnerable to the Year 2000 problems of these third parties. We began making
these contacts in the fourth quarter of 1998 and expect to continue assessing
risks associated with our third-party providers throughout 1999.
We have determined that our most reasonably likely worst case scenario would be
a failure of third-party systems necessary to move gas from our wells in the D-J
Basin to the market. In order to assess and mitigate risks in this regard, we
have organized a group of appropriate personnel from companies that are
interdependent for purposes of producing, gathering, compressing, transporting
and processing gas in the D-J Basin along the KN gathering system. An initial
meeting of these parties was held on March 2, 1999, with each company reviewing
the state of readiness of its critical path equipment in this integrated system.
The initial meeting revealed that all of the relevant equipment is either
believed to be compliant or expected to be compliant by the summer of 1999, and
that any failures can be manually overridden. However, the system appears to be
vulnerable to either a failure of utility power for the processing plants or a
failure of the pipeline owned by BP/Amoco that transports plant liquids from
BP/Amoco's Wattenberg gas plant. The parties agreed to investigate the state of
readiness of these systems and report this information to each other. The
members of the group also agreed to communicate significant information to each
other on a periodic basis, and to meet again in August of 1999.
We have also begun efforts to organize a similar group of parties connected to
the Duke gathering and processing system, the other major gas system in the D-J
Basin. By the end of the second quarter, we hope to achieve the same level of
comfort with respect to the Duke system that we have achieved with respect to
the KN system.
We expect to use our existing staff to address our Year 2000 readiness. Labor
costs attributable to our Year 2000 effort are expected to be less than $100,000
and we anticipate that expenditures for remedial software and replacement of IT
systems will be less than $50,000. We estimate that costs associated with
remediation or replacement of non-IT systems (being primarily office equipment
such as fax machines and copiers) will be less than $50,000.
We have considered other potential worst case scenarios including our inability
to execute financial transactions with our banks or other third parties whose
systems fail or malfunction and the inability to properly account for hedging
and trading transactions due to the inability to properly track pricing indices.
We currently have no reason to believe that any of these contingencies are
likely to occur or that our principal vendors, customers, and business partners
will not be Year 2000 compliant. We are not reasonably able to develop
contingency plans for dealing with these other worst case scenarios, but we do
not believe they are reasonably likely to occur. However, the extended failure
of certain key third-party systems could potentially have a material adverse
effect on us.
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<PAGE> 39
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. All statements other than statements of
historical facts included in this Form 10-K are forward-looking statements,
including without limitation, statements under "Legal Proceedings and
Environmental Issues," "Management's Discussion and Analysis of Financial
Condition and Results of Operations," and the "Notes to Consolidated Financial
Statements" regarding:
o reserves, their values and expected growth;
o planned capital expenditures;
o increases in oil and gas production;
o production economics;
o expected drilling opportunities;
o trends or expectations concerning oil and gas prices or market
characteristics;
o marketing, hedging and trading risks;
o our financial position, stability of cash flow, debt service
capabilities and capital availability;
o the amount of expected Section 29 tax credit payments;
o the ability to manage risk through hedging and similar activities;
o business strategy and other plans and objectives for future operations;
o potential liabilities or the expected absence thereof;
o the potential materiality and amount of Year 2000 compliance expenses
or the remoteness of the possibility of material losses associated
with the Year 2000 problem generally;
o 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, 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 following:
RISK FACTORS
VOLATILITY OF OIL AND GAS PRICES; MARKETABILITY OF PRODUCTION
Oil and gas prices can be extremely volatile and have recently declined
significantly from earlier levels. Gas prices affect us more than oil prices,
because most of our production and reserves are gas. At December 31, 1998,
approximately 78% of our estimated reserves were gas and approximately 78% of
our total production during 1998 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. Our 1999 budget is
39
<PAGE> 40
lower than prior years because of the lower oil and gas prices. Lower prices may
also reduce the amount of oil and gas that we can produce economically.
We cannot predict future oil and gas prices and prices may decline further.
Factors that cause this fluctuation include:
o changes in supply and demand
o the level of consumer product demand
o market uncertainty
o weather conditions
o federal and state regulation of oil and gas production
and transportation
o the price and availability of alternative fuels
o political conditions in the Middle East and other international
producing regions
o the foreign supply of oil and gas
o the price of oil and gas imports
o actions of state and local agencies, the United States and
foreign governments and international cartels
o 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, are
depressed and have at times been more volatile than the prices prevailing in the
broader United States gas market.
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.
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<PAGE> 41
EFFECTS OF LEVERAGE: EXISTING INDEBTEDNESS
As of December 31, 1998, our total long-term debt was approximately $534.9
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, 1998, excluding the effect of interest rate hedging
arrangements covering $80 million in principal amount of indebtedness, 43.0% of
our debt was floating rate obligations and 57.0% was fixed rate obligations,
with an overall range of interest rates from 6 1/2% to 9 7/8% per annum. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources" incorporated by reference in this
Form 10-K.
Our revolving Chase 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,
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<PAGE> 42
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 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 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
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<PAGE> 43
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. 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 property acquisitions, development or exploration activities. 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.
Our strategy will include continued exploitation and exploration of our existing
properties and may include opportunistic acquisitions of other oil and gas
properties. The successful acquisition of producing properties requires an
assessment of recoverable reserves, future oil and gas prices and operating
costs, potential environmental and other liabilities and other factors. These
assessments are necessarily inexact and their accuracy inherently uncertain. We
cannot assure you that our acquisition activities and exploration and
development projects will result in increases in reserves. Our operations may be
curtailed, delayed or canceled as a result of a lack of adequate capital and
other factors, such as title problems, weather, compliance with governmental
regulations or price controls, mechanical difficulties or shortages or delays in
the delivery of equipment. Furthermore, while our revenues may increase if
prevailing gas and oil prices increase significantly, our finding costs for
additional reserves could also increase. In addition, the costs of exploration
and development may materially exceed initial estimates.
RISKS OF HEDGING AND TRADING TRANSACTIONS
In order to manage our exposure to price risks in marketing our oil and gas and
in connection with our trading activities, we have in the past entered into and
may in the future enter into oil and gas futures contracts on the New York
Mercantile Exchange, fixed price delivery contracts and financial swaps. Those
transactions that are intended to reduce the effects of volatility of the price
of oil and gas may limit our potential gains if oil and
43
<PAGE> 44
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;
(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; or
(iv) a sudden, unexpected event materially affects oil or gas prices.
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. 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 may give rise to significant liabilities 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.
Recently there has been an increased level of regulation of oil and gas
activities in Colorado. For example, the Colorado Oil and Gas Conservation
Commission adopted, and is considering the adoption of additional, stricter
regulation of matters such as soil conservation, land reclamation, fluid
disposal and bonding of oil and gas companies. Additionally, various cities and
counties are currently reviewing their ordinances to determine the level of
regulatory authority, if any, they should assert over such matters. At present,
it cannot be determined to what degree stricter regulations, if adopted, would
adversely affect our operations.
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<PAGE> 45
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:
o no commercial productive oil or gas reservoir may be found;
o oil and gas drilling and production activities may be delayed
or canceled;
o title problems may delay or prohibit drilling, cause a loss of
interest in a well, or cause other problems or losses;
o weather problems may interfere with drilling or production; and
o mechanical difficulties or shortages or delays in the delivery of
drilling rigs and other equipment may occur.
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 wells 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 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
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<PAGE> 46
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.
46
<PAGE> 47
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.
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.
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<PAGE> 48
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 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 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.
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<PAGE> 49
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 well bore with more than one zone that may potentially
produce oil and/or gas.
Net acres or net wells. The sum of the working interests owned in gross acres or
gross wells.
Present value of estimated future net revenues, pretax present value at constant
prices of estimated future net revenues. Estimated future net revenues before
income taxes, discounted 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 for recompletion.
Recompletions. Within an existing wellbore, a recompletion involves completion
for production of a formation other than those which have previously been
productive. It is the mechanism by which behind-pipe reserves become productive.
Refrac. Within an existing wellbore, a refrac involves a new hydraulic fracture
stimulation of a currently or previously producing formation.
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.
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<PAGE> 50
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
CONSOLIDATED BALANCE SHEETS
HS Resources, Inc.
<TABLE>
<CAPTION>
December 31,
1998 1997
------------- -------------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 9,658,697 $ 6,907,708
Margin deposits 621,765 3,996
Accounts receivable
Oil and gas sales 20,528,042 23,052,931
Trading and transportation 14,011,992 14,366,469
Trade 4,079,887 3,579,327
Other 8,276,930 4,711,805
Lease and well equipment inventory, at cost 709,985 1,424,301
Prepaid expenses and other 2,378,092 1,341,997
------------- -------------
Total current assets 60,265,390 55,388,534
------------- -------------
OIL AND GAS PROPERTIES, AT COST, USING THE SUCCESSFUL
EFFORTS METHOD
Undeveloped acreage 108,029,622 163,824,956
Costs subject to depreciation, depletion and amortization 816,633,609 865,072,262
Less accumulated depreciation, depletion and amortization (175,729,105) (151,430,600)
------------- -------------
Net oil and gas properties 748,934,126 877,466,618
------------- -------------
GAS GATHERING AND TRANSPORTATION FACILITIES,
at cost, net of accumulated depreciation of $1,616,576
and $1,322,382 at December 31, 1998 and 1997, respectively 4,274,544 4,540,806
------------- -------------
OTHER ASSETS
Deferred charges and other, net 11,001,725 11,115,084
Office and transportation equipment and other property,
net of accumulated depreciation of $5,883,372
and $5,083,746 at December 31, 1998 and 1997, respectively 3,017,825 4,735,106
Notes receivable from officers for exercise
of stock options (Note 8) 2,245,813 --
Goodwill, net of accumulated amortization of $900,000
and $540,000 at December 31, 1998 and 1997, respectively (Note 2) 2,700,000 3,060,000
------------- -------------
Total other assets 18,965,363 18,910,190
------------- -------------
TOTAL ASSETS $ 832,439,423 $ 956,306,148
============= =============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
HS Resources, Inc.
<TABLE>
<CAPTION>
December 31,
1998 1997
-------------- -------------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable
Trade $ 21,378,518 $ 18,888,306
Revenue 20,915,255 17,460,848
Gas purchases 7,237,935 7,854,715
Accrued expenses
Ad valorem and production taxes 12,027,297 8,432,221
Interest 6,665,508 3,691,983
Other 7,381,932 7,359,030
Income taxes payable 2,792,929 --
Oil and gas production note payable 734,696 --
Current portion of long-term debt 30,000 30,000
-------------- -------------
Total current liabilities 79,164,070 63,717,103
-------------- -------------
ACCRUED AD VALOREM TAXES 12,450,721 10,606,402
-------------- -------------
DEFERRED REVENUE (NOTE 12) 8,908,363 9,872,870
-------------- -------------
LONG-TERM OIL AND GAS PRODUCTION NOTE PAYABLE -- 734,696
-------------- -------------
LONG-TERM BANK DEBT, NET OF CURRENT PORTION 230,000,000 412,000,000
-------------- -------------
9 7/8% SENIOR SUBORDINATED NOTES, DUE 2003, NET OF
unamortized discount of $287,625 and $346,125 at
December 31, 1998 and 1997, respectively 74,712,375 74,653,875
-------------- -------------
9 1/4% SERIES A SENIOR SUBORDINATED NOTES,
due 2006, net of unamortized discount of $611,887
and $689,587 at December 31, 1998
and 1997, respectively 149,388,113 149,310,413
-------------- -------------
9 1/4% SERIES B SENIOR SUBORDINATED NOTES,
due 2006, net of unamortized discount of $4,183,594
at December 31, 1998 80,816,406 --
-------------- -------------
DEFERRED INCOME TAXES 44,137,897 61,933,385
-------------- -------------
COMMITMENTS AND CONTINGENCIES (NOTE 11)
-------------- -------------
STOCKHOLDERS' EQUITY (NOTE 7)
Preferred stock -- --
Common stock, $.001 par value, 50,000,000 shares
authorized; 19,126,820 and 18,654,545 shares issued
and outstanding at December 31, 1998 and 1997,
respectively 19,127 18,655
Additional paid-in capital 188,195,831 183,191,380
Retained deficit (25,988,247) (7,371,790)
Deferred compensation (1,749,256) (144,300)
Treasury stock, at cost, 801,200 and 160,358 shares at
December 31, 1998 and 1997, respectively (7,615,977) (2,216,541)
-------------- -------------
Total stockholders' equity 152,861,478 173,477,404
-------------- -------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 832,439,423 $ 956,306,148
============== =============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
52
<PAGE> 53
CONSOLIDATED STATEMENTS OF OPERATIONS
HS Resources, Inc.
<TABLE>
<CAPTION>
For the years ended December 31,
1998 1997 1996
-------------- -------------- --------------
<S> <C> <C> <C>
REVENUES
Oil and gas sales $ 150,087,147 $ 137,251,046 $ 107,280,873
Trading and transportation 54,143,982 90,061,787 46,372,707
Other gas revenues 8,560,162 4,449,159 2,720,423
Interest income and other 1,404,492 1,942,894 582,067
-------------- -------------- --------------
Total revenues 214,195,783 233,704,886 156,956,070
-------------- -------------- --------------
EXPENSES
Production taxes 10,422,396 9,703,108 8,195,389
Lease operating 30,409,787 24,847,903 17,691,502
Cost of trading and transportation 50,450,697 88,402,012 45,699,154
Depreciation, depletion and amortization 61,223,401 45,756,965 36,599,878
Exploratory and abandonment 15,419,819 13,437,803 5,926,854
Geological and geophysical 14,308,184 17,049,115 4,262,249
Impairment and gain/loss on sale
of oil and gas properties 11,985,744 15,709,467 2,909,316
General and administrative 8,060,628 11,550,206 8,497,211
Interest 41,990,179 32,297,027 23,593,767
-------------- -------------- --------------
Total expenses 244,270,835 258,753,606 153,375,320
-------------- -------------- --------------
(Loss) income before benefit (provision)
for income taxes (30,075,052) (25,048,720) 3,580,750
BENEFIT (PROVISION) FOR INCOME TAXES 11,458,595 9,543,562 (1,364,266)
-------------- -------------- --------------
NET (LOSS) INCOME $ (18,616,457) $ (15,505,158) $ 2,216,484
============== ============== ==============
BASIC (LOSS) EARNINGS PER SHARE $ (1.00) $ (0.91) $ 0.16
============== ============== ==============
DILUTED (LOSS) EARNINGS PER SHARE $ (1.00) $ (0.91) $ 0.15
============== ============== ==============
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING 18,609,000 17,119,000 14,119,000
============== ============== ==============
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING ASSUMING DILUTION 18,609,000 17,119,000 14,552,000
============== ============== ==============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
53
<PAGE> 54
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
HS Resources, Inc.
<TABLE>
<CAPTION>
For the years ended December 31, 1998, 1997, and 1996
Common Stock Additional Retained Treasury Stock
-------------------- Paid-In Earnings Deferred -----------------------
Shares Amount Capital (Deficit) Compensation Shares Amount
---------- -------- ------------- ------------- ------------ -------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1995 10,948,680 $ 10,949 $ 97,717,908 $ 5,916,884 $ -- (75,077) $(1,039,303)
Purchase of treasury stock -- -- -- -- -- (113,817) (1,460,490)
Transfer of treasury stock to 401(k)
Plan -- -- (53,961) -- -- 20,025 246,708
Issuance of common stock for
Tide West Merger 6,169,181 6,169 65,231,025 -- -- -- --
Exercise of options by issuance
of treasury stock, including
income tax benefit -- -- 48,606 -- -- 46,917 582,551
Issuance of restricted stock 10,000 10 171,290 -- (171,300) -- --
Net income -- -- -- 2,216,484 -- -- --
---------- -------- ------------- ------------ ------------ -------- -----------
BALANCE, DECEMBER 31, 1996 17,127,861 17,128 163,114,868 8,133,368 (171,300) (121,952) (1,670,534)
---------- -------- ------------- ------------ ------------ -------- -----------
Purchase of treasury stock -- -- -- -- -- (101,247) (1,398,669)
Transfer of treasury stock to 40l(k)
Plan -- -- (68,011) -- -- 35,894 485,287
Issuance of common stock for
Amoco Acquisition 1,200,000 1,200 19,998,800 -- -- -- --
Exercise of options by issuance
of treasury stock, including
income tax benefit -- -- (34,355) -- -- 26,947 367,375
Issuance of restricted stock 2,500 3 44,997 -- (45,000) -- --
Amortization of deferred compensation -- -- -- -- 72,000 -- --
Issuance of common stock 12,203 12 135,393 -- -- -- --
Exercise of warrants and options 311,981 312 (312) -- -- -- --
Net loss -- -- -- (15,505,158) -- -- --
---------- -------- ------------- ------------ ------------ -------- -----------
BALANCE, DECEMBER 31, 1997 18,654,545 18,655 183,191,380 (7,371,790) (144,300) (160,358) (2,216,541)
---------- -------- ------------- ------------ ------------ -------- -----------
Purchase of treasury stock -- -- -- -- -- (721,937) (6,524,268)
Transfer of treasury stock to 40l(k)
Plan -- -- 7,419 -- -- 39,046 541,568
Exercise of options by issuance
of treasury stock, including
income tax benefit -- -- (115,247) -- -- 42,049 583,264
Issuance of restricted stock 32,126 33 427,685 -- (427,718) -- --
Amortization of deferred compensation -- -- -- -- 306,547 -- --
Issuance of performance shares 106,234 106 1,533,913 -- (1,534,019) -- --
Exercise of stock options, including
income tax benefit 337,021 336 3,200,912 -- -- -- --
Restricted stock forfeited (3,106) (3) (50,231) -- 50,234 -- --
Net loss -- -- -- (18,616,457) -- -- --
---------- -------- ------------- ------------ ------------ -------- -----------
BALANCE, DECEMBER 31, 1998 19,126,820 $ 19,127 $ 188,195,831 $(25,988,247) $ (1,749,256) (801,200) $(7,615,977)
---------- -------- ------------- ------------ ------------ -------- -----------
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
54
<PAGE> 55
CONSOLIDATED STATEMENTS OF CASH FLOWS
HS Resources, Inc.
<TABLE>
<CAPTION>
For the years ended December 31,
1998 1997 1996
------------ ------------ -------------
<S> <C> <C> <C>
Cash Flows from Operating Activities
Net (loss) income $(18,616,457) $(15,505,158) $ 2,216,484
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization 61,223,401 45,756,965 36,599,878
Impairment and gain/loss on sale of
oil and gas properties 11,985,744 15,709,467 2,909,316
Amortization of deferred charges and debenture issue costs 2,620,596 1,830,552 1,082,988
Transfer of treasury stock to 401(k) Plan 548,987 417,276 192,747
Gain on sale of fixed assets (234,558) -- (118,649)
Deferred income tax (benefit) provision (14,105,717) (10,553,851) 991,511
Decrease (increase) in accounts and notes receivable (1,186,319) 2,558,409 (21,784,122)
Increase in accounts payable and accrued expenses 10,069,263 7,947,122 16,157,951
Increase (decrease) in deferred revenue, net (964,507) 9,872,870 --
Other (1,256,936) 842,595 301,197
------------ ------------ -------------
Net cash provided by operating activities 50,083,497 58,876,247 38,549,301
------------ ------------ -------------
Cash Flows from Investing Activities
Exploration, development and leasehold costs (87,885,134) (39,994,620) (36,924,673)
Purchase of unproved and proved properties (4,753,675) (299,086,755) (129,982,687)
Cash payment for the Tide West Merger, net of cash acquired -- -- (85,125,084)
Gas gathering and transportation facilities additions (27,932) (156,889) (53,597)
Other property additions (859,427) (1,712,246) (1,056,547)
Proceeds from the sale of oil and gas properties 151,030,994 35,602,632 9,678,851
Proceeds from the sale of fixed assets and other property 1,233,814 -- 157,043
Increase in property related payables 3,694,398 11,272,110 8,130
------------ ------------ -------------
Net cash provided by (used in) investing activities 62,433,038 (294,075,768) (243,298,564)
------------ ------------ -------------
Cash Flows from Financing Activities
Proceeds from debt 154,750,000 337,000,000 536,316,596
Repayments of debt (256,000,000) (99,000,000) (315,258,900)
Tide West Merger costs -- -- (2,623,792)
Debt issuance costs (2,459,616) (2,947,934) (4,328,056)
Issuance of common stock -- 135,405 --
Exercise of options 468,338 333,020 631,157
Purchase of treasury stock (6,524,268) (1,398,669) (1,460,490)
Minority interest, net -- (779,349) 120,923
------------ ------------ -------------
Net cash (used in) provided by financing activities (109,765,546) 233,342,473 213,397,438
------------ ------------ -------------
Net Increase (Decrease) In Cash and Cash Equivalents 2,750,989 (1,857,048) 8,648,175
Cash and cash equivalents, beginning of year 6,907,708 8,764,756 116,581
------------ ------------ -------------
Cash and cash equivalents, end of year $ 9,658,697 $ 6,907,708 $ 8,764,756
============ ============ =============
Supplemental Cash Flow Disclosure
Interest paid, net of capitalized interest $ 34,016,266 $ 28,730,596 $ 20,078,634
Cash paid for income taxes, net of reimbursements $ 3,135,363 $ (413,297) $ 418,296
Schedule of noncash investing and financing activities:
Exchange of properties in Amoco Acquisition $ -- $ 23,000,000 $ --
Common stock issued in Amoco Acquisition $ -- $ 20,000,000 $ --
============ ============ =============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
55
<PAGE> 56
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
HS Resources, Inc.
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,
and exploits 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.
The Company, through its wholly-owned subsidiary, HS Energy Services, Inc.
("HSES"), markets its own gas production, markets gas owned by third parties and
actively trades both physical and financial positions in the gas commodities
market.
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 herein have been 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 statements of operations for the years ended December
31, 1997 and 1996, the effect of the accounting change was to decrease net
income by $26.8 million ($1.57 per diluted share) and $6.7 million ($0.46 per
diluted share), respectively.
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 basis. The depreciation of capitalized drilling
costs is based on the unit-of-production method using proved developed reserves
on a 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
56
<PAGE> 57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
future net cash flows. Accordingly, during 1998, 1997 and 1996, the Company
provided for $5.3 million, $1.6 million and $2.7 million, respectively, for such
impairments.
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.
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 In February 1997, the Financial Accounting Standards Board
issued SFAS No. 128, "Earnings Per Share." This statement provides computation,
presentation and disclosure requirements for earnings per share ("EPS"). The new
standard was adopted by the Company for
57
<PAGE> 58
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
the fiscal year ended 1997 and all prior periods have been retroactively
adjusted. There was no dilutive impact to weighted average shares for the fiscal
years ended December 31, 1998 and 1997. In the fiscal year ended December 31,
1996, the dilutive impact was 433,000 shares.
ACCRUED AD VALOREM TAXES The Company classifies as current ad valorem taxes
payable within one year. Other ad valorem taxes are classified as non-current
based on the required payment dates extending beyond one year.
DEFERRED CHARGES Legal and accounting fees, printing costs and other expenses
associated with the issuance of the Company's debt have been capitalized and are
being amortized over the remaining term of the debt.
GAS GATHERING AND TRANSPORTATION FACILITIES Depreciation of gas gathering and
transportation facilities is provided using the straight-line method over
estimated useful lives of 20 years.
OFFICE AND TRANSPORTATION EQUIPMENT Depreciation of office and transportation
equipment is provided using the straight-line method over estimated useful lives
which range from three to ten years.
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, 1998,
the Company's gas balancing position was approximately 462,000 Mcf overproduced.
USE OF ESTIMATES The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
NEW ACCOUNTING STANDARDS In June 1998, the Financial Accounting Standards Board
issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133"). This statement is effective for fiscal years beginning
after June 15, 1999 and 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
58
<PAGE> 59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
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. The effects of initial application of EITF
Issue 98-10 will be reported as a cumulative effect of a change in accounting
principle. Financial statements for periods prior to initial adoption of EITF
Issue 98-10 may not be restated. The Company anticipates that the cumulative
effect of this accounting change at January 1, 1999 will be immaterial.
NOTE 3 - DIVESTITURES AND ACQUISITIONS
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.
59
<PAGE> 60
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
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, 1998. The
condensed pro forma operating results assume that the Mid-Continent Sale had
occurred on January 1, 1998 (see Note 3). The condensed pro forma results are
not necessarily indicative of the results of operations had the Mid-Continent
Sale been consummated on January 1, 1998, and may not necessarily be indicative
of future performance.
<TABLE>
<CAPTION>
Twelve Months
Ended December 31,
1998
In thousands, except per share amounts (Unaudited)
- -------------------------------------- ------------------
<S> <C>
Revenues $ 196,878
Net loss $ (11,368)
Diluted loss per share $ (0.61)
Weighted average number of common
shares outstanding assuming dilution 18,609
</TABLE>
NOTE 5 - RISK MANAGEMENT
The Company uses financial instruments to reduce its exposure to market
fluctuations in the price and transportation cost of oil and gas. The Company's
general strategy is to hedge price and location risk with swap, collar, floor
and ceiling arrangements. In order to minimize risk, to the maximum extent
possible the Company hedges its production back to the wellhead. In addition to
hedging activities, the Company is engaged in using the financial markets to
capture trading margins. The Company has established policies with respect to
open positions which limit its exposure to market risk and require daily
reporting to management of the potential financial exposure resulting from both
hedging and trading activities.
60
<PAGE> 61
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
Hedging Activities Activities for hedging purposes are entered into by the
Company to manage its exposure to price and location risks in the marketing of
its oil and 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).
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, 1998,
the Company holds hedge swap positions as follows:
<TABLE>
<CAPTION>
Average Daily
Volume Settlement Price
Time Period (MMBtu) Location (per MMBtu)
- ----------- ------------- ---------- -----------
<S> <C> <C> <C>
January 99 - March 99 25,000 PEPL $ 2.40
January 99 - March 99 50,000 PEPL $ 2.45
April 99 - October 99 50,000 CIG $ 1.90
April 99 - October 99 50,000 NW $ 1.735
</TABLE>
The Company has hedged its expected oil production as follows:
<TABLE>
<CAPTION>
Monthly Hedged Settlement Price
Time Period Volume(Bbl) Location (per Bbl)
- ----------- -------------- ---------- -----------
<S> <C> <C> <C>
January 99 - December 99 30,400 NYMEX $ 16.45
January 99 - December 99 60,800 NYMEX $ 15.95
</TABLE>
61
<PAGE> 62
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
Additionally, with respect to the hedging of third party gas, the Company has
hedged 20.1 Bcf from January 1999 through June 2000 with offsetting physical
positions at settlement prices which are based upon NYMEX future prices or other
published indices.
Trading Activities The Company engages in the trading of various energy related
financial instruments which require payments to (or receipt of payments from)
counterparties based on the differential between a fixed and variable price for
the commodity, swap or other contractual arrangement. Company policy requires
that, within defined trading limits, financial instrument purchase and sales
contracts be balanced in terms of contract volumes and the timing of performance
and delivery obligations. As of December 31, 1998, all material open positions
were balanced with an offsetting position.
The Company accounts for these activities using the mark-to-market method of
accounting. During 1998, gains of $2.8 million were recognized in connection
with these activities and are included in "trading and transportation revenues."
Credit Risk While notional amounts are used to express the volume of various
derivative financial instruments, the amounts potentially subject to credit risk
in the event of nonperformance by the third parties are substantially smaller.
Counterparties to the swap, collar, floor and ceiling arrangements discussed
above are investment grade financial institutions. Accordingly, the Company does
not anticipate any material impact to its financial position or results of
operations as a result of nonperformance by the third parties to financial
instruments related to hedging activities or trading activities.
NOTE 6 - LONG-TERM DEBT
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.
62
<PAGE> 63
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
EVENT SUBSEQUENT TO BALANCE SHEET DATE (UNAUDITED) 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.
INTEREST RATE SWAPS 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 agreement, the difference between the
Company's fixed rate of 5.86% and the one-month LIBOR rate is received or paid
by the Company. As part of this hedging agreement, the Company's previous
hedging agreements were either cancelled or offset.
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, 1998 and 1997, the carrying amount of the
Company's 9 7/8% senior subordinated notes was $74.7 million and $74.7 million
and the estimated fair value was $73.9 million and $77.3 million, respectively.
At December 31, 1998 and 1997, the carrying amount of the 9 1/4% Series A senior
subordinated notes was $149.4 million and $149.3 million and the estimated fair
value was $144.0 million and $153.4 million, respectively. At December 31, 1998,
the carrying amount of the 9 1/4% Series B senior subordinated notes was $80.8
million and the estimated fair value was $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.
63
<PAGE> 64
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
Based on borrowing rates available for bank loans with similar collateral, the
fair values of the borrowings under the bank debt and other debt at December 31,
1998, are estimated to be their carrying value of $230.0 million and $0.8
million, respectively.
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
15,000,000 shares of $.001 par value Series A convertible preferred stock, of
which no shares are currently issued or outstanding. The stock has a stated
value of $13.50 and a liquidation preference of $1.00 per share.
SERIES A JUNIOR PREFERRED STOCK In February 1996, the Company authorized 300,000
shares of Series A junior preferred stock. The stock shall be issuable upon
exercise of rights (the "Rights") issued pursuant to the agreement dated as of
February 28, 1996, between the Company and Harris Trust Company of California,
as Rights Agent (the "Rights Agreement"). The Rights Agreement was designed to
protect the Company's shareholders in the event of takeover action that would
deny them the full value of their investment (the "Rights Plan").
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 the holder other than the
acquiring party to purchase either HS Resources 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, 1998 and 1997 and 746,262 warrants outstanding and
exercisable at $8.98 per share as of December 31, 1996.
64
<PAGE> 65
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
RESTRICTED STOCK During 1996 and 1997, the Company issued an aggregate of 12,500
shares of restricted stock and recorded cumulative deferred compensation of
$216,300. In 1998 the Company issued 32,126 shares of restricted stock and
recorded $427,718 of deferred compensation. 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.
ISSUANCE OF PERFORMANCE SHARES In May 1998, the Company's stockholders approved
the Amended and Restated 1997 Performance and Equity Incentive Plan (the "1997
Plan"). The 1997 Plan allows for the issuance of performance shares to
employees, officers and directors. The Company has issued 106,234 performance
shares as of December 31, 1998 and in connection with this issuance, recorded
deferred compensation of $1.5 million. Accelerated vesting of such shares is
dependent on the attainment by the Company of defined performance goals. These
shares vest over a maximum period of nine years with vesting to occur no earlier
than one-fourth of the shares in each of the first four years. For the year
ended December 31, 1998, the Company recorded amortization expense of $170,447
representing one-ninth of the total deferred compensation.
EVENT SUBSEQUENT TO BALANCE SHEET DATE (UNAUDITED) On February 25, 1999, the
Company entered into a total return equity swap with a financial institution,
whereby the financial institution acquired approximately 730,000 shares of HS
common stock from another investor. Under the terms of the swap agreement 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. At the earlier of July 1,
2000 or the termination of the swap agreement, the Company will receive any
increase in the market value of the shares (as defined) above the $6.0625
purchase price, or will pay for any loss; however, the Company may cover any
losses by issuing HS common stock to the financial institution if it chooses to
do so. HS will also pay certain commissions and finance costs.
NOTE 8 - RELATED PARTY TRANSACTIONS
In June 1998, in connection with the exercise of stock options, certain officers
of the Company issued to the Company full recourse notes, collateralized in part
by the common stock received, 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, 1998 was 7.75%.
65
<PAGE> 66
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
NOTE 9 - PROVISION FOR INCOME TAXES
The provision for income taxes consists of the following:
<TABLE>
<CAPTION>
1998 1997 1996
------------ ------------ -----------
<S> <C> <C> <C>
Current:
Federal $ 3,100,000 $ 200,000 $ 250,000
State 2,200,000 700,000 50,000
------------ ------------ -----------
5,300,000 900,000 300,000
------------ ------------ -----------
Deferred:
Federal (14,955,177) (9,319,714) 949,739
State (1,803,418) (1,123,848) 114,527
------------ ------------ -----------
(16,758,595) (10,443,562) 1,064,266
------------ ------------ -----------
$(11,458,595) $ (9,543,562) $ 1,364,266
============ ============ ===========
</TABLE>
The deferred income tax expense during the years ended December 31, 1998, 1997,
and 1996 results from the following:
<TABLE>
<CAPTION>
1998 1997 1996
------------ ------------ -----------
TYPE OF TEMPORARY DIFFERENCE
<S> <C> <C> <C>
Alternative minimum tax $ (3,100,000) $ 50,000 $ (250,000)
Depreciation, depletion and amortization (16,903,085) (17,864,938) (6,912,589)
Intangible drilling costs 25,427,940 16,529,602 1,183,913
Sales of properties (28,173,532) (5,966,696) 1,424,878
Operating loss carryforwards 5,990,082 (3,191,530) 5,618,064
------------ ------------ -----------
Deferred tax (benefit) provision $(16,758,595) $(10,443,562) $ 1,064,266
============ ============ ===========
</TABLE>
66
<PAGE> 67
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
The components of the net deferred tax liability as of December 31, 1998 and
1997 are as follows:
<TABLE>
<CAPTION>
1998 1997
------------- -------------
<S> <C> <C>
DEFERRED TAX LIABILITIES
Depreciation and basis difference $ 56,424,277 $ 77,152,961
------------- -------------
Deferred tax liability 56,424,277 77,152,961
DEFERRED TAX ASSETS
Tax effect of regular net operating loss 5,918,265 11,962,286
Alternative minimum tax credit 4,047,825 937,000
Statutory depletion carryforwards 2,320,290 2,320,290
All other --- ---
------------- -------------
Deferred tax assets, net 12,286,380 15,219,576
------------- -------------
Net deferred tax liability $ 44,137,897 $ 61,933,385
============= =============
</TABLE>
The effective tax rate during 1998, 1997 and 1996 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
$15.5 million available at December 31, 1998, to offset future taxable income.
These carryforwards, if not previously utilized, expire in 2004 through 2011.
The Company has an alternative minimum tax ("AMT") credit carryforward of
approximately $4.0 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 million which can be used to reduce taxable
income in the future and is not subject to expiration.
67
<PAGE> 68
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
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 1998). Employees may receive
matching contributions from the Company in an amount determined by the Board of
Directors. All 401(k) matching 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, 1998, the Company accrued approximately $750,000 for the 1998
401(k) matching contribution, however, the final amount has not yet been
approved by the Board of Directors. Contributions to the plans were $548,987 and
$417,276 in 1997 and 1996, 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 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 1998, 1997 and
1996. During 1996, the Company implemented SFAS No. 123, "Accounting for Stock
Based Compensation." Had compensation cost for these plans been determined
consistent with SFAS 123, net of the effect of forfeitures and tax, the Company
would have recorded compensation costs of $806,930, $298,000 and $66,000 in
1998, 1997 and 1996, respectively.
68
<PAGE> 69
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
The following table summarizes activity with respect to outstanding stock
options for the years 1998, 1997 and 1996:
<TABLE>
<CAPTION>
Weighted Average
Shares Option Price
--------- ----------------
<S> <C> <C>
Outstanding at December 31, 1995
(613,369 shares exercisable) 744,437 $ 10.81
Granted 94,000 12.37
Exercised (46,917) 12.00
Forfeited (18,000) 23.92
--------- ----------
Outstanding at December 31, 1996
(626,670 shares exercisable) 773,520 10.63
Granted 163,000 14.60
Exercised (40,650) 9.23
Forfeited (7,000) 14.14
--------- ----------
Outstanding at December 31, 1997
(635,370 shares exercisable) 888,870 11.39
Granted 713,223 11.26
Exercised (379,070) 6.95
Forfeited (198,386) 14.14
--------- ----------
Outstanding at December 31, 1998
(448,432 shares exercisable) 1,024,637 $ 13.89
========= ==========
</TABLE>
Of the 1,024,637 options outstanding at December 31, 1998, 448,432 options are
fully vested and have exercise prices between $9.00 and $25.00, with a weighted
average exercise price of $14.52 and a weighted average remaining contractual
life of 5.07 years. The remaining 576,205 options have exercise prices between
$9.00 and $25.00, with a weighted average exercise price of $13.40 and a
weighted average remaining contractual life of 5.07 years.
69
<PAGE> 70
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted-average
assumptions used for grants in 1998, 1997 and 1996, respectively: risk free
interest rates ranging from 4.53% to 4.74%; expected dividend yield of 0%;
expected life of 7.27 years; expected volatility of 45%, 39% and 67%,
respectively.
EVENT SUBSEQUENT TO BALANCE SHEET DATE (UNAUDITED) 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 1945.
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 the date of this report, 185,000 shares of common stock had
been issued at prices ranging from $5.625 to $5.94.
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 are working together with the EPA to develop characterization
studies of the site, and have caused the facility to be permanently closed.
Based on the Company's current knowledge and its expectation of proportionate
reimbursement from other parties who utilized the facility, the Company does not
believe that its share of the reclamation costs will have a material impact on
its financial condition or results of operations. By agreement with other
contributing parties, the Company is currently paying approximately 50% of the
costs associated with the project, but after recovery from additional liable
parties, the Company's percentage share of overall costs may be reduced to 40%.
The Company's share of total costs associated with the project are currently
estimated to be approximately $1.3 million. The Company has incurred
approximately $1.1 million at December 31, 1998 for its portion of the costs.
The remaining estimated liability has been accrued at year end.
70
<PAGE> 71
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
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.
JW LAWSUIT On July 28, 1998, JW Resources, Inc. brought suit against HS 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. JW is seeking damages
the defendants allegedly caused to JW's leasehold rights in certain oil and gas
leases in Potter County, Texas. The complaint alleges that HS and HSRTW, Inc.,
as the owner and/or operator of deep rights in these leases, damaged the
plaintiff's shallow rights in the same lands by failing to cement the shallow
zones during the drilling of its wells to the deep formations. HS and HSRTW have
denied each claim made by the plaintiff and believe that they have substantial
scientific and legal defenses to each claim and intend to vigorously defend
against them. Although it is not possible to predict the outcome of this matter
at trial, the Company believes that the litigation will not have a material
adverse effect on its results of operations or financial condition.
OPERATING LEASES The Company is obligated under noncancelable operating leases
for office space and certain equipment. Total rental expense related to these
leases was $2,568,966, $2,382,498 and $1,653,378 for December 31, 1998, 1997 and
1996, respectively. Future minimum lease payments as of December 31, 1998 are:
<TABLE>
<CAPTION>
Year ended December 31,
- -----------------------
<S> <C>
1999 $ 2,087,385
2000 1,819,992
2001 1,679,808
2002 1,635,229
2003 1,232,142
Thereafter 672,900
--------------
Total minimum lease payments $ 9,127,456
==============
</TABLE>
71
<PAGE> 72
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
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, 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 will enable the third parties to earn tax credits
associated with future oil and gas production. In 1998 and 1997, the Company
received approximately $6.4 million and $10.6 million, respectively, in prepaid
tax credits. 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. During the year ended December 31, 1998, the Company
recognized approximately $7.4 million of deferred revenue. The Company
recognized approximately $8.6 million, $4.4 million and $2.7 million of other
gas revenues associated with all tax credits during the years ended December 31,
1998, 1997 and 1996, respectively.
NOTE 13 - OIL AND GAS ACTIVITIES
MAJOR PURCHASERS In 1998, sales to Duke Energy Field Service, Amoco and Ultramar
Diamond Shamrock Corporation accounted for approximately $26,402,000,
$15,677,000 and $15,222,000 or 17.6%, 10.5% and 10.1% of total oil and gas
sales, respectively. In 1997, sales to Duke Energy Field Service and Amoco
accounted for approximately $28,704,000 and $23,286,000 or 20.9% and 17.0% of
total oil and gas sales, respectively. In 1996, sales to Amoco and Panenergy
accounted for approximately $29,300,000 and $22,800,000 or 27.3% and 21.2%, of
total oil and gas sales, respectively.
72
<PAGE> 73
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
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:
<TABLE>
<CAPTION>
Year ended December 31,
1998 1997 1996
----------- ------------ -----------
<S> <C> <C> <C>
Property acquisition costs
Unproved $15,413,692 $130,169,443 $ 34,569,303
Proved $12,614,987 $226,457,644 $348,492,280
----------- ------------ ------------
Exploration costs $10,747,108 $ 12,856,148 $ 2,100,119
----------- ------------ ------------
Development costs $78,736,318 $ 44,374,882 $ 36,176,991
----------- ------------ ------------
Depreciation, depletion and
amortization $58,991,755 $ 43,421,229 $ 34,675,797
----------- ------------ ------------
Depreciation, depletion and
amortization per equivalent
barrel of oil production $ 4.87 $ 4.69 $ 4.55
=========== =========== ============
</TABLE>
73
<PAGE> 74
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
NOTE 14 - BUSINESS SEGMENT INFORMATION (IN THOUSANDS)
The Company is an independent energy company engaged in the following
activities:
o acquisition, development, exploitation, exploration and production of
oil and gas
o marketing of oil and gas
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
OPERATING REVENUES:
<S> <C> <C> <C>
Oil and gas sales D-J Basin $ 139,259 $ 96,357 $ 82,271
Oil and gas sales Gulf Coast 2,344 1,754 --
Oil and gas sales Mid-Continent and other 17,045 43,589 27,730
Trading and transportation 142,374 148,994 60,718
Intersegment eliminations (88,231) (58,932) (14,345)
----------- ----------- -----------
$ 212,791 $ 231,762 $ 156,374
=========== =========== ===========
OPERATING (LOSS) INCOME:
D-J Basin $ 51,538 $ 47,144 $ 35,450
Gulf Coast (19,471) (20,265) (3,052)
Mid-Continent and other (15,252) (9,638) 3,649
Trading and transportation 5,713 1,960 1,024
Intersegment eliminations (2,436) (681) (537)
----------- ----------- -----------
OPERATING INCOME 20,092 18,520 36,534
Other income and expense (50,167) (43,569) (32,953)
----------- ----------- -----------
(LOSS) INCOME BEFORE INCOME TAXES $ (30,075) $ (25,049) $ 3,581
=========== =========== ===========
IDENTIFIABLE ASSETS (AT DECEMBER 31):
Oil and gas properties D-J Basin $ 904,538 $ 826,344 $ 465,848
Oil and gas properties Gulf Coast 21,750 13,306 4,631
Oil and gas properties Mid-Continent and other 4,267 195,110 264,086
Trading and transportation 3,786 3,735 3,718
Corporate 8,715 9,684 7,992
----------- ----------- -----------
$ 943,056 $ 1,048,179 $ 746,275
=========== =========== ===========
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE:
Oil and gas properties D-J Basin $ 50,735 $ 23,147 $ 25,154
Oil and gas properties Gulf Coast 510 274 --
Oil and gas properties Mid-Continent and other 8,042 20,290 9,816
Trading and transportation 416 382 187
Corporate 1,520 1,664 1,443
----------- ----------- -----------
$ 61,223 $ 45,757 $ 36,600
=========== =========== ===========
CAPITAL EXPENDITURES AND ACQUISITIONS:
Oil and gas properties D-J Basin $ 70,980 $ 324,103 $ 161,091
Oil and gas properties Gulf Coast 8,661 7,566 5,566
Oil and gas properties Mid-Continent and other 13,026 7,569 81,827
Trading and transportation 51 17 3,718
Corporate 838 1,695 939
----------- ----------- -----------
$ 93,556 $ 340,950 $ 253,141
=========== =========== ===========
</TABLE>
74
<PAGE> 75
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
NOTE 15 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
OIL AND GAS NET RESERVES The following unaudited tables set forth the estimated
quantities of net proved oil and gas reserves for the Company and the changes in
total proved reserves as of December 31, 1998, 1997 and 1996. All such reserves
are located in the United States. The amounts as of December 31, 1998, 1997 and
1996, 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.
75
<PAGE> 76
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
ANALYSIS OF CHANGES IN PROVED RESERVES
<TABLE>
<CAPTION>
Oil Gas
--------------------------------
(Thousands of
Proved developed and undeveloped reserves (Barrels) Cubic Feet)
---------- -------------
<S> <C> <C>
Balance, December 31, 1995 19,587,760 298,777,400
Revision of previous estimates 4,868 (880,400)
Extensions, discoveries and other additions 1,424,288 41,786,934
Production (1,923,435) (34,163,010)
Purchases of reserves in place 15,648,402 351,707,690
Sales of reserves in place (127,503) (12,807,314)
---------- ------------
Balance, December 31, 1996 34,614,380 644,421,300
Revision of previous estimates (2,726,993) (36,809,862)
Extensions, discoveries and other additions 2,098,560 42,623,250
Production (2,399,743) (41,125,200)
Purchases of reserves in place 14,839,796 332,793,612
Sales of reserves in place (1,067,900) (62,049,000)
---------- ------------
Balance, December 31, 1997 45,358,100 879,854,100
Revision of previous estimates (7,025,315) (54,285,458)
Extensions, discoveries and other additions 5,878,000 185,207,500
Production (2,630,047) (56,969,167)
Purchases of reserves in place 391,700 7,671,900
Sales of reserves in place (4,528,738) (164,430,075)
---------- ------------
Balance, December 31, 1998 37,443,700 797,048,800
========== ============
Proved developed reserves
December 31, 1996 23,111,490 508,923,100
========== ============
December 31, 1997 26,027,500 611,198,400
========== ============
December 31, 1998 23,557,900 561,410,000
========== ============
</TABLE>
76
<PAGE> 77
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
STANDARDIZED MEASURE The standardized measure of discounted future net cash
flows, and changes therein related to proved oil and gas reserves are as
follows:
<TABLE>
<CAPTION>
Year ended December 31,
1998 1997 1996
--------------- --------------- ---------------
<S> <C> <C> <C>
Future cash inflows $ 1,923,811,000 $ 2,771,498,000 $ 3,045,480,000
Future production costs (460,431,000) (681,825,000) (646,925,700)
Future development costs (335,904,000) (360,007,000) (170,708,400)
--------------- --------------- ---------------
Undiscounted future pre-tax cash flows 1,127,476,000 1,729,666,000 2,227,845,900
Undiscounted future income taxes (215,319,976) (410,680,162) (619,110,885)
--------------- --------------- ---------------
Undiscounted future pre-tax cash flows,
net of future income taxes 912,156,024 1,318,985,838 1,608,735,015
10% discount factor (476,275,662) (689,534,976) (790,717,180)
--------------- --------------- ---------------
Standardized measure of discounted future
net cash flows $ 435,880,362 $ 629,450,862 $ 818,017,835
--------------- --------------- ---------------
Discounted future pre-tax cash flows
excluding income taxes $ 531,905,100 $ 822,466,600 $ 1,130,923,000
=============== =============== ===============
</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.
77
<PAGE> 78
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
The following are the principal sources of change in the standardized measure of
discounted future net cash flows:
<TABLE>
<CAPTION>
Year ended December 31,
1998 1997 1996
-------------- -------------- --------------
<S> <C> <C> <C>
Standardized measure of discounted future
net cash flows, beginning of the year $ 629,450,862 $ 818,017,835 $ 199,258,449
Sales and transfers of oil and gas produced,
net of production costs (108,622,877) (101,796,457) (80,450,583)
Sales of reserves in place (157,546,549) (63,971,600) (14,892,716)
Net changes in prices and production costs:
On beginning of year reserves (199,052,383) (464,696,728) 281,677,346
On reserves purchased during the year -- -- 200,295,822
Extensions, discoveries and improved recovery,
less related costs 162,530,400 60,509,682 80,749,964
Changes in future development costs 2,807,428 (22,474,120) (2,088,801)
Development costs incurred during the period
that reduced future development costs 78,539,678 43,489,081 32,335,836
Revisions of previous quantity estimates (55,617,580) (46,871,761) (1,679,406)
Purchase of reserves in place 6,328,400 265,063,849 345,252,515
Accretion of discount 73,099,354 113,282,652 25,704,490
Net change in income taxes 5,517,839 121,793,142 (255,118,714)
Changes in production rates (timing) and other (1,554,210) (92,894,713) 6,973,633
-------------- -------------- --------------
Standardized measure of discounted future
net cash flows, end of the year $ 435,880,362 $ 629,450,862 $ 818,017,835
============== ============== ==============
</TABLE>
78
<PAGE> 79
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
Estimated future cash inflows are computed by applying year-end prices of oil
and gas to year-end quantities of proved reserves. Future price changes are
considered only to the extent provided by contractual arrangements. Estimated
future development and production costs are determined by estimating the
expenditures to be incurred in developing and producing the proved oil and gas
reserves held by the Company as of the end of the year, based on year-end costs
and assuming continuation of existing economic conditions. Estimated future
income tax expenses are calculated by applying year-end statutory tax rates
(adjusted for permanent differences) to estimated future pretax net cash flows
related to proved oil and gas reserves, less the tax basis of the properties
involved. No deductions were made for general overhead, depreciation and other
indirect costs. The average year-end prices used in the projections were
$9.99/Bbl of oil and $1.94/Mcf of gas at December 31, 1998, $16.38/Bbl of oil
and $2.31/Mcf of gas at December 31, 1997, and $24.92/Bbl of oil and $3.39/Mcf
of gas at December 31, 1996.
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.
79
<PAGE> 80
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
HS Resources, Inc.
NOTE 16 - QUARTERLY FINANCIAL DATA (UNAUDITED)
The Company's quarterly results of operations are summarized as follows (in
thousands, except per share data):
<TABLE>
<CAPTION>
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 $ (3,056) $ (8,335) $(11,307)
-------- -------- -------- --------
Diluted earnings (loss) per share $ 0.22 $ (0.16) $ (0.44) $ (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>
<TABLE>
<CAPTION>
1996
Mar. 31 June 30 Sept. 30 Dec. 31
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Operating revenues $ 14,153 $ 26,767 $ 47,566 $ 67,888
Operating expenses 10,367 17,998 35,321 57,599
-------- -------- -------- --------
Operating income 3,786 8,769 12,245 10,289
-------- -------- -------- --------
Net income (loss) $ (361) $ 1,690 $ 1,806 $ (918)
-------- -------- -------- --------
Diluted earnings (loss) per share $ (0.03) $ 0.14 $ 0.10 $ (0.05)
-------- -------- -------- --------
</TABLE>
80
<PAGE> 81
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,
1998 and 1997, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1998. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of HS Resources, Inc.
and subsidiaries as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
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 24, 1999
81
<PAGE> 82
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
Items 10-13, Inclusive:
These items have been omitted in accordance with the instructions of
Form 10-K. Pursuant to Regulation 14A of the Securities Exchange Act, the
Registrant will file with the Commission on or before April 30, 1997, a
definitive proxy statement which will include information with respect to the
election of directors.
82
<PAGE> 83
PART IV
Item 14. EXHIBITS
(a) Exhibits.
3.1 Amended and Restated Certificate of Incorporation of the Company.
(Incorporated herein by reference to Exhibit 3.1 to the Company's
Registration Statement on Form S-1, No. 33-52774, filed October 2,
1992.)
3.2 Third Amended and Restated Bylaws of the Company adopted December 16,
1996. (Incorporated by reference to Exhibit 3.2 to the Company's
Registration Statement on Form S-4, No 333-19433, filed January 8,
1997.)
4.1 Form of Indenture dated December 1, 1993, entered into between the
Company and the Trustee. (Incorporated by reference to Exhibit 4.7 to
Amendment No. 3 to the Company's Registration Statement on Form S-3,
No. 33-70354, filed November 23, 1993.)
4.2 Indenture dated November 27, 1996, among the Company, Orion
Acquisition, Inc., HSRTW, Inc., and Harris Trust and Savings Bank as
Trustee. (Incorporated by reference to Exhibit 4.2 to the Company's
Registration Statement on Form S-4, No 333-19433, filed January 8,
1997.)
4.3 First Supplemental Indenture dated November 25, 1996 among the Company,
Orion Acquisition, Inc., HSRTW, Inc., and Harris Trust and Savings Bank
as Trustee. (Incorporated by reference to Exhibit 4.3 to the Company's
Registration Statement on Form S-4, No 333-19433, filed January 8,
1997.)
10.1 Common Stock Purchase Warrant dated July 12, 1990 by the Company to
James E. Duffy. (Incorporated by reference to Exhibit 10.5 to the Form
8, Second Amendment to Form 10, filed April 8, 1991.)
10.2 HS Resources, Inc. Rule 701 Compensatory Benefit Plan. (Incorporated by
reference to Exhibit 10.5.2 to the Form 8, Second Amendment to Form 10,
filed April 8, 1991.)
10.3 1992 Directors' Stock Option Plan. (Incorporated by reference to
Exhibit 10.10 to Amendment No. 1 to the Company's Registration
Statement on Form S-1, No. 33-52774, filed November 9, 1992.)
10.3.1 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
83
<PAGE> 84
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 Interest Exchange Agreement between The Chase Manhattan Bank, N.A. and
the Company dated May 9, 1995. (Incorporated by reference to Exhibit
10.19 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1995, filed August 14, 1995.)
10.8 Agreement for Purchase and Sale of Assets, dated as of February 24,
1996, among the Company, Basin Exploration, Inc. ("Basin") and Orion
Acquisition, Inc. ("Orion"). (Incorporated by reference to Exhibit 2.3
to the Company's Form 8-K, filed March 12, 1996.)
10.9 Agreement for Purchase and Sale of Assets [Wattenberg], dated as of
February 24, 1996, among the Company, Orion and Basin. (Incorporated by
reference to Exhibit A to the Company's Schedule 13D relating to Basin
Exploration, Inc., filed on March 6, 1996.)
10.10 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.)
10.11 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.)
10.12 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.)
10.13 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.)
10.14 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.)
10.15 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.)
84
<PAGE> 85
10.16 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.)
10.17 Purchase and Sale Agreement between Wattenberg Resources Land L.L.C.
and Wattenberg Gas Investments, LLC dated May 21, 1996. (Incorporated
by reference to Exhibit 10.33 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.18 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.)
10.19 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.)
10.20 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.)
10.21 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.)
10.22 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.)
10.23 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.)
10.24 Purchase Agreement dated November 27, 1996, among the Company, Orion,
HSRTW, Inc., Salomon Brothers Inc., Chase Securities Inc., Lehman
Brothers Inc., and Prudential Securities Incorporated. (Incorporated by
reference to Exhibit 10.40 to the Company's Registration Statement on
Form S-4, No 333-19433, filed January 8, 1997.)
10.25 Registration Agreement dated November 27, 1996, among the Company,
Orion, HSRTW, Inc. and Salomon Brothers Inc. in its individual capacity
and as agent for Chase Securities Inc., Lehman Brothers Inc., and
Prudential Securities Incorporated. (Incorporated by reference to
Exhibit 10.41 to the Company's Registration Statement on Form S-4, No
333-19433, filed January 8, 1997.)
85
<PAGE> 86
10.26 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.)
10.27 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.)
10.28 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.)
10.29 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.)
10.30 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.)
10.31 Fifth Amendment and Supplement to Amended, Restated and Consolidated
Mortgage, Assignment of Production, Security Agreement and Financing
Statement between HS Resources (Mortgagor) and The Chase Manhattan
Bank, as agent for the Lenders, effective as of December 15, 1997.
(Incorporated by reference to Exhibit 10.37 to the Company's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1998, filed May 14,
1998.)
10.32 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.)
10.33 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.)
10.34 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.)
10.35 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.)
86
<PAGE> 87
10.36 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.)
10.37 Amended and Restated 1997 Performance and Equity Incentive Plan.
(Incorporated by reference to Exhibit A to the Company's Definitive
Proxy Statement for its Annual Meeting of Stockholders held on May 20,
1998, filed April 24, 1998.)
10.38 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.)
10.39 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.)
10.40* 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.
10.41* 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.
10.42 1999 Non-Compensatory Stock Purchase Plan. (Incorporated by reference
as Exhibit 4.1 to Form S-8 filed January 25, 1999.)
10.43* 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
10.44* 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
10.45* 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.
27* Financial Data Schedule
* Filed herewith
- -------------------------
b. Reports on Form 8-K.
Report dated August 13, 1998, filing the August 13, 1998 press release
in connection with the Company's second quarter earnings release. Item 5.
87
<PAGE> 88
Report dated September 3, 1998, filing the September 1, 1998 press
release in connection with the closing of the sale by the Company of its
wholly owned subsidiary, HSRTW, Inc., to Universal Resources Corporation.
Item 2.
Amendment to report dated September 15, 1998, filing the pro forma
financial information for the sale by the Company of its wholly owned
subsidiary, HSRTW, Inc., to Universal Resources Corporation. Item 7 (A).
Report dated November 17, 1998, filing the November 10, 1998 press
release in connection with the Company's third quarter earnings release.
Item 5.
Report dated December 11, 1998, filing the Underwriting Agreement,
Indenture and T-1 Statement relating to the Company's $85 million debt
offering. Item 7(c).
Report dated December 14, 1998, filing the December 11, 1998, press
release in connection with the Company's $85 million debt offering. Item
7(c).
Report dated January 13, 1999, filing the December 29, 1998, press
release in connection with the Company's stock repurchase program. Item 5.
Report dated March 23, 1999, filing the February 25, 1999, press
releases in connection with the Company's fourth quarter and year-end
earnings release and the Company's operational update. Item 5.
88
<PAGE> 89
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, on this 31st day of March.
HS RESOURCES, INC.
By /s/ Nicholas J. Sutton
------------------------------
Nicholas J. Sutton
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed by the following persons in the capacities indicated on this
31st day of March.
<TABLE>
<CAPTION>
Signature Title
--------- -----
<S> <C>
/s/ Nicholas J. Sutton Chairman of the Board, Chief
------------------------------ Executive Officer
Nicholas J. Sutton (Principal Executive Officer)
/s/ P. Michael Highum
------------------------------
P. Michael Highum President and Director
/s/ James E. Duffy Chief Financial Officer
------------------------------ and Director
James E. Duffy (Principal Financial Officer)
/s/ Annette Montoya Vice President - Accounting
------------------------------ and Controller
Annette Montoya (Principal Accounting Officer)
/s/ Kenneth A. Hersh Director
------------------------------
Kenneth A. Hersh
/s/ Michael J. Savage Director
------------------------------
Michael J. Savage
/s/ Philip B. Smith Director
------------------------------
Philip B. Smith
</TABLE>
<PAGE> 90
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit Number Description
- -------------- -----------
<S> <C>
10.40 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.
10.41 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.
10.43 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
10.44 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
10.45 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.
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>
<PAGE> 1
EXHIBIT 10.40
SIXTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT
THIS SIXTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT
(this "Amendment") is dated as of December 10, 1998 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 and the Fifth Amendment to Amended
and Restated Credit Agreement dated as of September 1, 1998 (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; and
B. The Borrower, the Agent, and the Lenders now desire to make certain
amendments to the Credit Agreement.
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. The definitions "Indentures," "Subordinated Debt," and "Subordinated
Notes" in Section 1.02 of the Credit Agreement are hereby amended to read as
follows:
"Indentures" shall mean the 93 Indenture, the 96 Indenture
and the 98 Indenture.
"Subordinated Debt" shall mean the Debt of the Company
evidenced by the Subordinated Notes or the Indentures.
<PAGE> 2
"Subordinated Notes" shall mean the 93 Subordinated Notes,
the 96 Subordinated Notes and the 98 Subordinated Notes.
3. Section 1.02 of the Credit Agreement is hereby supplemented, where
alphabetically appropriate, with the addition of the following definitions:
"98 Indenture" shall mean the Indenture between the Borrower,
as Issuer, and Harris Trust and Savings Bank, as Trustee, providing for
the issuance of $85,000,000 of Senior Subordinated Notes due November
15, 2006 and all renewals, extensions and modifications permitted by
the terms of this Agreement.
"98 Subordinated Notes" shall mean the Senior Subordinated
Notes issued pursuant to the 98 Indenture.
"Sixth Amendment" shall mean that certain Sixth Amendment to
Amended and Restated Credit Agreement dated as of December 10, 1998,
among the Borrower, the Lenders and the Agent.
"Sixth Amendment Effective Date" shall mean the effective date
of the Sixth Amendment and shall be the same date as the effective date
of the 98 Indenture; provided, that the conditions required by Section
14 of the Sixth Amendment have been satisfied.
"Year 2000 Problem" shall mean the risk that the computer
hardware or software applications or other data processing capacities
used by the parties may be unable to recognize and perform properly
date-sensitive functions involving certain dates before and any date
after December 31, 1999."
4. During the period from and after the Sixth Amendment Effective
Date until the first Redetermination Date thereafter, the amount of the
Borrowing Base shall be $280,000,000.
5. Section 2.08(e) of the Credit Agreement is hereby amended to
read as follows:
"(e) The Agent shall promptly notify in writing the Borrower
and the Lenders of the Borrowing Base set by the Super Majority
Lenders. If the amount of the proposed Borrowing Base is a decrease
from the amount of the previous Borrowing Base, it shall become
effective upon receipt of written notice by the Borrower. If the amount
of the proposed Borrowing Base is an increase of the amount of the
previous Borrowing Base, within five (5) Business Days of the receipt
of such written notice, any Lender that had in writing disagreed to
such increase (each a "Dissenting Lender") shall send written notice to
the Agent stating that either (i) it agrees that its Commitment shall
be calculated by its current Percentage Share of the proposed Borrowing
Base or (ii) it agrees to be bound by some lesser Commitment
("Dissenting Lender's Reduced Prorata Borrowing Base"), but in no event
less than the amount of its Commitment in
-2-
<PAGE> 3
effect before the effectiveness of the proposed Borrowing Base. If the
Agent does not receive a written notice from a Dissenting Lender in
which it makes the above election within the five Business Day period,
the absence of such notice shall be deemed to be an election by such
Dissenting Lender of option (i) above. If any Dissenting Lender timely
elects option (ii) above, the Agent will calculate the resulting
Borrowing Base which will equal (y) the proposed Borrowing Base minus
(z) the sum, for each Dissenting Lender that timely elected option
(ii), of the differences of (A) the product of (1) each such Dissenting
Lender's current Percentage Share times (2) the proposed Borrowing Base
minus (B) such Dissenting Lender's Reduced Prorata Borrowing Base. The
Agent will calculate the new Percentage Share for each Lender based on
each Lender's prorata share of the new Borrowing Base. The Agent will
also calculate the Aggregate Maximum Credit Amounts for all the Lenders
and the Maximum Credit Amount for each Lender. The Maximum Credit
Amount for each Dissenting Lender that elected option (ii) shall
reduce, the Maximum Credit Amount for each of the other Lenders shall
remain the same and the Aggregate Maximum Credit Amount shall reduce.
The Borrower will issue a new Note to each Dissenting Lender that
elected option (ii) in the amount of such Lender's new Maximum Credit
Amount to replace the outstanding Note held by such Lender.
6. Section 7 of the Credit Agreement is hereby supplemented with
the addition of the following Section 7.23:
"7.23 Year 2000 Provision. Any reprogramming or other
correcting required to permit the proper functioning, in and following
the year 2000, of the Borrower's computer systems necessary to permit
the Borrower to conduct its business without a Material Adverse Effect
(including systems and equipment supplied by others) and the testing of
all such systems and equipment, as so reprogrammed, will be completed
by June 30, 1999. Borrower reasonably expects to be able to identify
and remedy Year 2000 Problems associated with its equipment containing
embedded microchips on or before June 30, 1999. The cost to the
Borrower of such reprogramming or other remedying and testing of the
reasonably foreseeable consequences of the Year 2000 Problem to the
Borrower (including, without limitation, reprogramming errors and the
failure of others' systems or equipment) will not to Borrower's
knowledge result in a Default or Material Adverse Effect. Except for
such of the reprogramming referred to in the first sentence of this
Section 7.23 as may be necessary, the computer and management
information systems of the Borrower and its Subsidiaries are and, with
ordinary course upgrading and maintenance, will continue to be,
sufficient to permit the Borrower to conduct its business without
Material Adverse Effect."
7. Section 8.01(i) of the Credit Agreement is hereby amended to
read as follows:
"(i) At each time of delivery of the financial statements
required to be delivered pursuant to Sections 8.01(a) and (b) a report
in form and substance satisfactory to the Agent setting forth the use
of proceeds from asset sales and
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<PAGE> 4
demonstrating compliance with Sections 4.03(b)(i) of the 96 Indenture
and of the 98 Indenture."
8. Section 8.01 of the Credit Agreement is hereby amended by
adding the following sentence at the end of such section:
"The above compliance certificate will include a statement that the
Year 2000 remediation efforts of the Borrower and the Subsidiaries are
proceeding as scheduled and indicating whether an auditor, regulator,
or third party consultant has issued a management letter or other
communication regarding the Year 2000 exposure, program, or progress of
the Borrower and/or the Subsidiaries."
9. Section 9.01(g) of the Credit Agreement is hereby amended to
read in its entirety as follows:
"(g) the Subordinated Debt not to exceed at any time
$75,000,000 of principal outstanding under the 93 Subordinated Notes,
$150,000,000 of principal outstanding under the 96 Subordinated Notes
and $85,000,000 of principal outstanding under the 98 Subordinated
Notes;"
10. Section 9.01(o) of the Credit Agreement is hereby amended to
read as follows:
"(o) other Debt of the Borrower not to exceed $5,000,000
outstanding at any time in the aggregate."
11. Section 9.04(a) of the Credit Agreement is amended to read as
follows:
"(a) redeem shares from its stockholders not to exceed $10,000,000
in the aggregate since the Closing Date; and"
12. The first sentence of Section 9.14 of the Credit Agreement is
amended to read as follows:
"The Borrower will not permit its Interest Coverage Ratio as of the end
of any fiscal quarter of the Borrower (calculated quarterly at the end
of each fiscal quarter) to be less than 2.30 to 1.00 through the
quarter ending December 31, 1999, 2.50 to 1.00 thereafter through the
quarter ending December 31, 2000 and 2.75 to 1.00 thereafter."
13. Section 9.15(iv) of the Credit Agreement is hereby amended to read
as follows:
"(iv) during the period between two consecutive Redetermination Dates,
sales in the ordinary course of business of Oil and Gas Properties
which shall not exceed $10,000,000 in the aggregate including, but not
limited to, the sale of the Hydrocarbon Interests representing
approximately the final 20% of the gas reserves in a Section 29 tax
credit transaction as the values are set forth in the most recent
Reserve Report."
-4-
<PAGE> 5
14. Section 9.20 of the Credit Agreement is amended by adding the
following subsection (c):
"(c) The Borrower will not modify or amend the terms of the 98
Indenture as in existence on Sixth Amendment Effective Date and any
related documents without the consent of the Majority Lenders, if the
effect of such modification or amendment would be to shorten the time
for payment on any 98 Subordinated Notes, increase the principal amount
of the 98 Subordinated Notes above $85,000,000, increase the rate of
interest on any 98 Subordinated Note or change the method of
calculating interest so as to effectively increase the rate of interest
on any 98 Subordinated Note, change the form of the reverse side of the
Security issued under the 98 Indenture, change any of the provisions of
Section 6.01, Articles 3,4,5,10,11 and 12, and Section 1.01 as to any
of the definitions used in or relating to any of the above Sections and
Articles, or any other provisions which would detrimentally effect the
rights of the Lenders. The Indebtedness shall first be irrevocably and
indefeasibly paid in full in cash, or the immediate payment thereof
duly provided for in cash, and this Agreement terminated before the
Borrower, any Subsidiary or any Person acting on behalf of the Borrower
or any Subsidiary shall directly or indirectly pay, prepay, redeem,
retire, repurchase or otherwise acquire for value, or make a deposit
pursuant to Article 8 of the 98 Indenture in respect of, or make any
other prepayment, payment or distribution (whether in cash, property,
securities or accommodation thereof or otherwise) on account of the
principal of (or premium, if any) or interest on, any 98 Subordinated
Note or Subsidiary Subordinated Debt related thereto; except that the
Borrower may make payments of interest that has accrued and is payable
on the 98 Subordinated Notes pursuant to the terms of the 98 Indenture
and pay the principal of the 98 Subordinated Notes at the stated
maturity of November 15, 2006 provided that no Event of Default exists
and is continuing and such payment shall not cause an Event of
Default."
15. Annex I of the Credit Agreement is hereby replaced by Annex I to
this Amendment.
16. As set forth in the compliance certificate delivered by the
Borrower in connection with the delivery of the Borrower's September 30, 1998
quarterly financial statements, the Borrower excluded commitment fees paid from
cash interest payments and rounded the Interest Coverage Ratio to the nearest
1/100th. The Lenders hereby agree that the rounding to the nearest 1/100th and
the exclusion of commitment frees from cash interest payments were acceptable
for such calculation of the Interest Coverage Ratio for the quarter ending
September 30, 1998 and any quarters before. For future calculations of the
Interest Coverage Ratio the parties hereto agree that commitment fees paid shall
be included in cash interest payments and all numbers will be rounded downward
to the nearest 1/100th.
17. This Amendment shall become binding on the Lenders when, and only
when, the
-5-
<PAGE> 6
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 Super Majority Lenders;
(b) a copy of the 98 Indenture;
(c) the issuance of the 98 Subordinated Notes for the
principal amount of $85,000,000;
(d) the fee payable to each Lender which consent to this
Amendment equal to the greater of $5,000 or an amount equal to 0.1% of
such Lender's Percentage Share of the new Borrowing Base; and
(e) such other documents as it or its counsel may reasonably
request.
18. 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.
19. 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.
20. 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.
21. 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.
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..
[SIGNATURES OMITTED]
-6-
<PAGE> 1
EXHIBIT 10.41
SEVENTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT
THIS SEVENTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this
"Amendment") is dated as of December 31, 1998 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 and the Sixth Amendment
to Amended and Restated Credit Agreement dated as of December 10, 1998 (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; and
B. The Borrower, the Agent, and the Lenders now desire to make certain
amendments to the Credit Agreement.
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. The definition "EBITDA" in Section 1.02 of the Credit Agreement is
hereby deleted.
3. Section 1.02 of the Credit Agreement is hereby supplemented, where
alphabetically appropriate, with the addition of the following definitions:
"EBITDAX" shall mean, for any period, the sum of Consolidated
Net Income for such period plus the following expenses or charges to
the extent deducted from Consolidated Net Income in such period:
interest, taxes, depreciation, depletion and amortization and
exploration, geological and geophysical expenses.
<PAGE> 2
"Seventh Amendment" shall mean that certain Seventh Amendment
to Amended and Restated Credit Agreement dated as of December 31, 1998,
among the Borrower, the Lenders and the Agent.
4. Section 9.13 of the Credit Agreement is hereby amended to read in
its entirety as follows:
"Section 9.13 Tangible Net Worth. The Borrower will not permit
its Tangible Net Worth to be less than $130,000,000 at any time plus
50% of its Consolidated Net Income, if positive, (determined in
accordance with GAAP) for each fiscal year of the Company, ending after
the fiscal year ended December 31, 1998."
5. Section 9.14 of the Credit Agreement is hereby amended by
substituting the word "EBITDAX" for the word "EBITDA".
6. The Majority Lenders hereby consent to an amendment of the 93
Indenture, an amendment of the 96 Indenture and an amendment of the 98 Indenture
as outlined on Schedule 1 hereto.
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; and
(b) such other documents as it or its counsel may reasonably
request.
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.
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.
<PAGE> 3
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.
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..
[SIGNATURES OMITTED]
<PAGE> 1
EXHIBIT 10.43
SUPPLEMENTAL INDENTURE
SUPPLEMENTAL INDENTURE (this "Supplemental Indenture"), dated as of
March 11, 1999 among HS RESOURCES, INC., a Delaware corporation (the "Company"),
and HARRIS TRUST AND SAVINGS BANK, an Illinois banking corporation, as trustee
under the Indenture referred to below (the "Trustee").
W I T N E S S E T H :
WHEREAS, the Company has heretofore executed and delivered to the
Trustee an Indenture (as amended from time to time, the "Indenture"), dated as
of December 1, 1993, providing for the issuance of $75,000,000 aggregate
principal amount of 9-7/8% Senior Subordinated Notes due 2003;
WHEREAS, effective December 31, 1998, the Company changed its method of
accounting from the full cost method to the successful efforts method. Two
changes to the Indenture need to be made in order that the Indenture operate
materially as originally intended under the Company's new method of accounting.
WHEREAS, pursuant to Section 9.1 of the Indenture, the Trustee and the
Company are authorized to execute and deliver this Supplemental Indenture;
NOW THEREFORE, in consideration of the foregoing and for other good and
valuable consideration, the receipt of which is hereby acknowledged, the Company
and the Trustee mutually covenant and agree for the equal and ratable benefit of
the holders of the Securities as follows:
1. Definitions.
(a) Capitalized terms used herein without definition shall
have the meanings assigned to them in the Indenture.
(b) For all purposes of this Supplemental Indenture, except
as otherwise herein expressly provided or unless the context otherwise requires:
(i) the terms and expressions used herein shall have the same meanings as
corresponding terms and expressions used in the Indenture; and (ii) the words
"herein," "hereof" and "hereby" and other words of similar import used in this
Supplemental Indenture refer to this Supplemental Indenture as a whole and not
to any particular section hereof.
<PAGE> 2
2. Consolidated Net Income. The definition of Consolidated Net
Income shall read as follows; with the change indicated by underline:
"Consolidated Net Income" means, with respect to the Company
and its Restricted Subsidiaries, for any period, the aggregate of the
net income (or loss) of the Company and its Restricted Subsidiaries for
such period, determined on a consolidated basis in accordance with
GAAP; provided that there shall be excluded from such net income (to
the extent otherwise included therein) (a) the net income of any Person
in which the Company or any Restricted Subsidiary has an interest
(which interest does not cause the net income of such other Person to
be consolidated with the net income of the Company and its Restricted
Subsidiaries in accordance with GAAP), except to the extent of the
amount of dividends or distributions actually paid in such period by
such other Person to the Company or to a Restricted Subsidiary, (b) the
net income (but not loss) of any Restricted Subsidiary to the extent
that the declaration or payment of dividends or similar distributions
or transfers or loans by that Restricted Subsidiary is not at the time
permitted by operation of the terms of its charter or any agreement,
instrument, judgment, decree, order, statute, rule or governmental
regulation applicable to such Restricted Subsidiary, or is otherwise
restricted or prohibited in each case determined in accordance with
GAAP, (c) the net income (or loss) of any Person acquired in a
pooling-of-interests transaction for any period prior to the date of
such transaction, (d) any extraordinary gains or losses, including
gains or losses attributable to Asset Dispositions not in the ordinary
course of business, and (e) the cumulative effect of a change in
accounting principle and any gains or losses attributable to writeups
or writedowns of assets, and (f) any reduction for exploratory and
abandonment costs and geological and geophysical costs, net of the
income tax effect reflecting the income tax rate in the Company's
financial statements for the applicable period.
3. Governing Law. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED
BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK BUT
WITHOUT GIVING EFFECT TO APPLICABLE PRINCIPLES OF CONFLICTS OF LAW TO THE EXTENT
THAT THE APPLICATION OF THE LAWS OF ANOTHER JURISDICTION WOULD BE REQUIRED
THEREBY.
4. Counterparts. The parties may sign any number of copies of
this Supplemental Indenture. Each signed copy shall be an original, but all of
them together represent the same agreement.
5. Effect of Headings. The Section headings herein are for
convenience only and shall not effect the construction thereof.
2
<PAGE> 3
IN WITNESS WHEREOF, the parties hereto have caused this Supplemental
Indenture to be duly executed as of the date first above written.
HS RESOURCES, INC.
By:
-----------------------------------
Name: James E. Duffy
Title: Chief Financial Officer
HARRIS TRUST AND SAVINGS BANK, as Trustee
By:
-----------------------------------
Name: Daniel G. Donovan
Title: Assistant Vice President
3
<PAGE> 1
EXHIBIT 10.44
SUPPLEMENTAL INDENTURE
SUPPLEMENTAL INDENTURE (this "Supplemental Indenture"), dated as of
March 11, 1999 among HS RESOURCES, INC., a Delaware corporation (the "Company"),
and HARRIS TRUST AND SAVINGS BANK, an Illinois banking corporation, as trustee
under the Indenture referred to below (the "Trustee").
W I T N E S S E T H :
WHEREAS, the Company has heretofore executed and delivered to the
Trustee an Indenture (as amended from time to time, the "Indenture"), dated as
of November 27, 1996, providing for the issuance of $150,000,000 aggregate
principal amount of 9-1/4% Senior Subordinated Notes due 2006;
WHEREAS, effective December 31, 1998, the Company changed its method of
accounting from the full cost method to the successful efforts method. Two
changes to the Indenture need to be made in order that the Indenture operate
materially as originally intended under the Company's new method of accounting.
WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee and the
Company are authorized to execute and deliver this Supplemental Indenture;
NOW THEREFORE, in consideration of the foregoing and for other good and
valuable consideration, the receipt of which is hereby acknowledged, the Company
and the Trustee mutually covenant and agree for the equal and ratable benefit of
the holders of the Securities as follows:
1. Definitions.
(a) Capitalized terms used herein without definition shall
have the meanings assigned to them in the Indenture.
(b) For all purposes of this Supplemental Indenture, except
as otherwise herein expressly provided or unless the context otherwise requires:
(i) the terms and expressions used herein shall have the same meanings as
corresponding terms and expressions used in the Indenture; and (ii) the words
"herein," "hereof" and "hereby" and other words of similar import used in this
Supplemental Indenture refer to this Supplemental Indenture as a whole and not
to any particular section hereof.
<PAGE> 2
2. Consolidated Net Income. The definition of Consolidated Net
Income shall read as follows; with the change indicated by underline:
"Consolidated Net Income" of any Person means, for any period,
the aggregate net income (or net loss, as the case may be) of such
Person and its Restricted Subsidiaries for such period on a
consolidated basis, determined in accordance with GAAP; provided that
there shall be excluded therefrom, without duplication, (i) items
classified as extraordinary (other than the tax benefit of the
utilization of net operating loss carry-forwards and alternative
minimum tax credits); (ii) any gain or loss, net of taxes, on the sale
or other disposition of assets (including the Capital Stock of any
other Person) in excess of $1,000,000, from any sale or disposition or
series of related sales or dispositions (but in no event shall this
clause (ii) apply to the sale of oil and gas inventories in the
ordinary course of business); (iii) the net income of any Subsidiary of
such specified Person to the extent the transfer to that Person of that
income is restricted by contract or otherwise, except for any cash
dividends or cash distributions actually paid by such Subsidiary to
such Person during such period; (iv) the net income (or net loss) of
any other Person in which such specified Person or any of its
Restricted Subsidiaries has an ownership interest (which ownership
interest does not cause the net income of such other Person to be
consolidated with the net income of such specified Person in accordance
with GAAP or is an interest in a consolidated Unrestricted Subsidiary),
except to the extent of the amount of cash dividends or other cash
distributions actually paid to such Person or its Restricted
Subsidiaries by such other Person during such period; (v) the net
income (or net loss) of any Person acquired by such specified Person or
any of its Restricted Subsidiaries in a pooling-of-interests
transaction for any period prior to the date of such acquisition; (vi)
any gain or loss, net of taxes, realized on the termination of any
employee pension benefit plan; (vii) any adjustments of a deferred tax
liability or asset pursuant to Statement of Financial Accounting
Standards No. 109 which result from changes in enacted tax laws or
rates; (viii) the cumulative effect of a change in accounting
principles; and (ix) any reduction for exploratory and abandonment
costs and geological and geophysical costs, net of the income tax
effect reflecting the income tax rate in the Company's financial
statements for the applicable period.
3. EBITDA. The definition of EBITDA shall read as follows, with
the change indicated by strikethrough:
"EBITDA" means with respect to any Person for any period, the
Consolidated Net Income of such Person and its consolidated Restricted
Subsidiaries for such period, plus (i) the sum of, to the extent
reflected in the consolidated income statement of such Person and its
Restricted Subsidiaries for such period from which Consolidated Net
Income is determined and deducted in the determination of such
Consolidated Net Income, without duplication, (A)
2
<PAGE> 3
income tax expense (but excluding income tax expense relating to (1)
sales or other disposition of assets (including the Capital Stock of
any other Person) resulting in a net gain in excess of $1,000,000 and
(2) the redemption or retirement of any Indebtedness prior to its
Stated Maturity), (B) Consolidated Interest Expenses, (C) depreciation
and depletion expense, (D) amortization expense, (E) any loss, net of
taxes, in connection with the redemption or retirement of any
Indebtedness prior to its Stated Maturity, and (F) any other noncash
charges, including, without limitation, unrealized foreign exchange
losses; less (ii) the sum of, to the extent reflected in the
consolidated income statement of such Person and its Restricted
Subsidiaries for such period from which Consolidated Net Income is
determined and added in the determination of such Consolidate Net
Income, without duplication, (A) income tax recovery (but excluding
income tax recovery relating to (1) sales or other dispositions of
assets (including the Capital Stock of any other Person) resulting in a
net loss in excess of $1,000,000 and (2) the redemption or retirement
of any Indebtedness prior to its Stated Maturity), (B) any gain, net of
taxes, in connection with the redemption or retirement of any
Indebtedness prior to its Stated Maturity and (C) unrealized foreign
exchange gains.
4.Governing Law. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND
CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK BUT WITHOUT
GIVING EFFECT TO APPLICABLE PRINCIPLES OF CONFLICTS OF LAW TO THE EXTENT THAT
THE APPLICATION OF THE LAWS OF ANOTHER JURISDICTION WOULD BE REQUIRED THEREBY.
5. Counterparts. The parties may sign any number of copies of this
Supplemental Indenture. Each signed copy shall be an original, but all of them
together represent the same agreement.
6. Effect of Headings. The Section headings herein are for convenience
only and shall not effect the construction thereof.
IN WITNESS WHEREOF, the parties hereto have caused this Supplemental
Indenture to be duly executed as of the date first above written.
HS RESOURCES, INC.
By:
----------------------------------------
Name: James E. Duffy
Title: Chief Financial Officer
HARRIS TRUST AND SAVINGS BANK, as Trustee
By:
----------------------------------------
Name: Daniel G. Donovan
Title: Assistant Vice President
3
<PAGE> 1
EXHIBIT 10.45
SUPPLEMENTAL INDENTURE
SUPPLEMENTAL INDENTURE (this "Supplemental Indenture"), dated as of
March 11, 1999 among HS RESOURCES, INC., a Delaware corporation (the "Company"),
and HARRIS TRUST AND SAVINGS BANK, an Illinois banking corporation, as trustee
under the Indenture referred to below (the "Trustee").
W I T N E S S E T H :
WHEREAS, the Company has heretofore executed and delivered to the
Trustee an Indenture (as amended from time to time, the "Indenture"), dated as
of December 11, 1998, providing for the issuance of $85,000,000 aggregate
principal amount of 9-1/4% Series B Senior Subordinated Notes due 2006;
WHEREAS, effective December 31, 1998, the Company changed its method of
accounting from the full cost method to the successful efforts method. Two
changes to the Indenture need to be made in order that the Indenture operate
materially as originally intended under the Company's new method of accounting.
WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee and the
Company are authorized to execute and deliver this Supplemental Indenture;
NOW THEREFORE, in consideration of the foregoing and for other good and
valuable consideration, the receipt of which is hereby acknowledged, the Company
and the Trustee mutually covenant and agree for the equal and ratable benefit of
the holders of the Securities as follows:
1. Definitions.
(a) Capitalized terms used herein without definition shall
have the meanings assigned to them in the Indenture.
(b) For all purposes of this Supplemental Indenture, except
as otherwise herein expressly provided or unless the context otherwise requires:
(i) the terms and expressions used herein shall have the same meanings as
corresponding terms and expressions used in the Indenture; and (ii) the words
"herein," "hereof" and "hereby" and other words of similar import used in this
Supplemental Indenture refer to this Supplemental Indenture as a whole and not
to any particular section hereof.
<PAGE> 2
2. Consolidated Net Income. The definition of Consolidated Net
Income shall read as follows; with the change indicated by underline:
"Consolidated Net Income" of any Person means, for any period,
the aggregate net income (or net loss, as the case may be) of such
Person and its Restricted Subsidiaries for such period on a
consolidated basis, determined in accordance with GAAP; provided that
there shall be excluded therefrom, without duplication, (i) items
classified as extraordinary (other than the tax benefit of the
utilization of net operating loss carry-forwards and alternative
minimum tax credits); (ii) any gain or loss, net of taxes, on the sale
or other disposition of assets (including the Capital Stock of any
other Person) in excess of $1,000,000, from any sale or disposition or
series of related sales or dispositions (but in no event shall this
clause (ii) apply to the sale of oil and gas inventories in the
ordinary course of business); (iii) the net income of any Subsidiary of
such specified Person to the extent the transfer to that Person of that
income is restricted by contract or otherwise, except for any cash
dividends or cash distributions actually paid by such Subsidiary to
such Person during such period; (iv) the net income (or net loss) of
any other Person in which such specified Person or any of its
Restricted Subsidiaries has an ownership interest (which ownership
interest does not cause the net income of such other Person to be
consolidated with the net income of such specified Person in accordance
with GAAP or is an interest in a consolidated Unrestricted Subsidiary),
except to the extent of the amount of cash dividends or other cash
distributions actually paid to such Person or its Restricted
Subsidiaries by such other Person during such period; (v) the net
income (or net loss) of any Person acquired by such specified Person or
any of its Restricted Subsidiaries in a pooling-of-interests
transaction for any period prior to the date of such acquisition; (vi)
any gain or loss, net of taxes, realized on the termination of any
employee pension benefit plan; (vii) any adjustments of a deferred tax
liability or asset pursuant to Statement of Financial Accounting
Standards No. 109 which result from changes in enacted tax laws or
rates; (viii) the cumulative effect of a change in accounting
principles; and (ix) any reduction for exploratory and abandonment
costs and geological and geophysical costs, net of the income tax
effect reflecting the income tax rate in the Company's financial
statements for the applicable period.
3. EBITDA. The definition of EBITDA shall read as follows, with
the change indicated by strikethrough:
"EBITDA" means with respect to any Person for any period, the
Consolidated Net Income of such Person and its consolidated Restricted
Subsidiaries for such period, plus (i) the sum of, to the extent
reflected in the consolidated income statement of such Person and its
Restricted Subsidiaries for such period from which Consolidated Net
Income is determined and deducted in the determination of such
Consolidated Net Income, without duplication, (A)
2
<PAGE> 3
income tax expense (but excluding income tax expense relating to (1)
sales or other disposition of assets (including the Capital Stock of
any other Person) resulting in a net gain in excess of $1,000,000 and
(2) the redemption or retirement of any Indebtedness prior to its
Stated Maturity), (B) Consolidated Interest Expenses, (C) depreciation
and depletion expense, (D) amortization expense, (E) any loss, net of
taxes, in connection with the redemption or retirement of any
Indebtedness prior to its Stated Maturity, and (F) any other noncash
charges, including, without limitation, unrealized foreign exchange
losses; less (ii) the sum of, to the extent reflected in the
consolidated income statement of such Person and its Restricted
Subsidiaries for such period from which Consolidated Net Income is
determined and added in the determination of such Consolidate Net
Income, without duplication, (A) income tax recovery (but excluding
income tax recovery relating to (1) sales or other dispositions of
assets (including the Capital Stock of any other Person) resulting in a
net loss in excess of $1,000,000 and (2) the redemption or retirement
of any Indebtedness prior to its Stated Maturity), (B) any gain, net of
taxes, in connection with the redemption or retirement of any
Indebtedness prior to its Stated Maturity and (C) unrealized foreign
exchange gains.
4. Governing Law. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY,
AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK BUT WITHOUT
GIVING EFFECT TO APPLICABLE PRINCIPLES OF CONFLICTS OF LAW TO THE EXTENT THAT
THE APPLICATION OF THE LAWS OF ANOTHER JURISDICTION WOULD BE REQUIRED THEREBY.
5. Counterparts. The parties may sign any number of copies of this
Supplemental Indenture. Each signed copy shall be an original, but all of them
together represent the same agreement.
6. Effect of Headings. The Section headings herein are for
convenience only and shall not effect the construction thereof.
IN WITNESS WHEREOF, the parties hereto have caused this Supplemental
Indenture to be duly executed as of the date first above written.
HS RESOURCES, INC.
By:
-----------------------------------
Name: James E. Duffy
Title: Chief Financial Officer
HARRIS TRUST AND SAVINGS BANK, as Trustee
By:
-----------------------------------
Name: Daniel G. Donovan
Title: Assistant Vice President
3
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
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 30, 1999
<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 30, 1999, (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.
/s/ Williamson Petroleum Consultants, Inc.
---------------------------------------------
Williamson Petroleum Consultants, Inc.
Houston, Texas
March 30, 1999
<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, 1998, filed with
the Securities and Exchange Commission (SEC) on March 30, 1999, 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 30, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 9,658,697
<SECURITIES> 0
<RECEIVABLES> 46,896,851
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0
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<INCOME-TAX> 11,458,595
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