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.
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.
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."
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.
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.
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.
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:
Item 2.
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.
(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
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.
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.
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.
(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.
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.
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.
PRODUCTIVE OIL AND GAS WELLS
As of December 31, 1998, we owned interests in the following productive oil and gas wells:
(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.
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).
PRODUCTION
The following table sets forth our oil and gas production data during the periods indicated.
(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.
Item 3.
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
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.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
Item 5.
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.
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.
Item 6.
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.
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.
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.
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.
COMPARISON OF YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
D-J BASIN OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES)
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.
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
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)
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
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.
MID-CONTINENT AND OTHER OIL AND GAS SALES (IN THOUSANDS EXCEPT AVERAGE PRICES)
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(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.
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.
TRADING AND TRANSPORTATION (IN THOUSANDS)
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)
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
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)
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.
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.
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.
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.
As of December 31, 1998, we hold hedge swap positions as follows:
We have hedged our expected oil production as follows:
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.
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
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
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.
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
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.
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,
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
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
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.
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
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.
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.
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.
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.
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.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONSOLIDATED BALANCE SHEETS HS Resources, Inc.
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS HS Resources, Inc.
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF OPERATIONS HS Resources, Inc.
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY HS Resources, Inc.
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS HS Resources, Inc.
The accompanying notes are an integral part of these consolidated financial statements.
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
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
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
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.
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.
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.
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:
The Company has hedged its expected oil production as follows:
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.
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.
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.
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%.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
NOTE 9 - PROVISION FOR INCOME TAXES
The provision for income taxes consists of the following:
The deferred income tax expense during the years ended December 31, 1998, 1997, and 1996 results from the following:
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:
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.
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.
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:
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.
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.
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:
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.
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:
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
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
ANALYSIS OF CHANGES IN PROVED RESERVES
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:
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.
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:
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.
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):
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
Item 9.
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.
PART IV
Item 14.
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
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.)
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.)
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.)
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
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
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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.
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.
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.
EXHIBIT INDEX