Item 1. BUSINESS
THE COMPANY
HS Resources, Inc. ("HSR" or "the Company") is a leading United States independent energy company engaged in the development, acquisition, exploitation, exploration, production and marketing of oil and natural gas. Through its experienced management and technical staff, the Company has consistently increased reserves and production, and has established itself as one of the most efficient operators in the industry. HSR has created a diversified asset base in three core geographic areas: the Denver-Julesburg Basin ("D-J Basin") of the Rocky Mountains, the Anadarko and Arkoma Basins of the Mid-Continent and the on-shore Gulf Coast area. It has done so by executing a large scale development drilling program focused in the Wattenberg Field area of the D-J Basin and through the acquisition of all of the D-J Basin properties owned by Basin Exploration, Inc. ("Basin") (the "Acquisitions"), the merger with Tide West Oil Company (the "Merger") and the formation of Gulf Coast joint ventures. The Company believes that each core geographic area presents operational and financial opportunities, positioning the Company to maximize the benefits of its more predictable, long-lived D-J Basin production, while providing meaningful exposure to potential exploitation and exploration projects in the Mid-Continent and Gulf Coast which exhibit higher return potential. HSR has an inventory of growth opportunities that includes in excess of 2,000 infill, development and exploratory drilling locations and over 1.1 million gross undeveloped acres.
The Company has achieved substantial growth in reserves, production, revenues and operating cash flow over the past five years. HSR has increased reserves from 20.8 MMBoe as of December 31, 1990, to 142.0 MMBoe as of December 31, 1996. HSR also increased production from 0.9 MMBoe for the year ended December 31, 1991, to 7.6 MMBoe for the year ended December 31, 1996. Oil and natural gas revenues and operating cash flow (defined as net income before depreciation, depletion and amortization and deferred income taxes) also have grown significantly, increasing from $12.8 million and $5.4 million, respectively, for the year ended December 31, 1991, to $107.3 million and $56.5 million, respectively, for the year ended December 31, 1996.
At December 31, 1996, the Company's reserves had an estimated pre-tax present value (discounted at 10%) of $1,131 million. Natural gas constituted approximately 76% of the Company's reserves and approximately 76% of the Company's reserves were classified as proved developed. At December 31, 1996, the Company operated approximately 74% of its 3,562 wells. Management believes that its ability to control the operations of its wells and to minimize overhead expenses has contributed to the Company achieving one of the lowest cost structures in the industry.
The Company is a Delaware corporation organized in 1987 to consolidate interests owned and/or managed by certain members of the current management team. The Company's principal subsidiaries are Orion Acquisition, Inc. ("Orion"), which holds the assets acquired in the Acquisitions, HSRTW, Inc. ("HSRTW"), which holds the assets acquired through the Merger, and Tide West Trading & Transport Company ("TWTT") (the name of which the Company intends to change to HS Energy Services, Inc. in the near future). The Company's principal executive office is located at One Maritime Plaza, Fifteenth Floor, San Francisco, California 94111 and its telephone number at such address is (415) 433-5795.
BUSINESS STRATEGY
HSR's objective is to maximize its long-term value through aggressive growth in its oil and natural gas reserves and production. The Company has successfully achieved its goals through an ongoing strategy of (i) increasing its diversified long-lived asset base, (ii) building a substantial inventory of development, exploitation and exploration projects, (iii) utilizing state-of-the-art exploration, drilling and production techniques, (iv) effecting consolidation in its core geographic areas, (v) maintaining low operating costs, (vi) capturing downstream value and (vii) maximizing financial flexibility.
o Increase Diversified Long-lived Asset Base. HSR has assembled a diversified portfolio of predictable, long-lived properties, which, in the aggregate, generate significant high margin production and cash flows. HSR presently owns interests in 3,562 gross wells and had an aggregate reserves-to-production ratio of 15:1 as of December 31, 1996. The Company's current reserve mix consists of approximately 76% natural gas and 24% oil, with most wells producing both oil and natural gas. The Company is diversified geographically and geologically with core producing properties located in the D-J Basin and the Mid-Continent area and also owns extensive undeveloped leaseholds in the Gulf Coast and Rocky Mountain regions.
o Build a Substantial Inventory of Development, Exploitation and Exploration Projects. The Company intends to continue expanding its substantial portfolio of development, exploitation and exploration projects. As of December 31, 1996, HSR had identified approximately 970 development drillsites and 750 potential infill drillsites in the D-J Basin. The lower risk infill and development projects in the D-J Basin are complemented by relatively higher risk and potentially higher return exploitation and exploration projects in the Mid-Continent and Gulf Coast regions. Based upon preliminary interpretation of seismic and geologic data, the Company has identified approximately 218 exploitation and development drilling locations in the Mid-Continent area and approximately 60 exploitation and exploration projects and leads in its Gulf Coast project areas.
o Utilize Advanced Exploration, Drilling and Production Techniques. In the D-J Basin, the Company has tested and is evaluating the use of coiled tubing drilling and is using both sophisticated fracturing technologies and directional drilling to enhance production and obtain additional reserves from existing wellbores. In order to improve its exploitation and exploration drilling success rates, the Company utilizes 3-D seismic extensively, including advanced imaging techniques of coherence cube or continuity processing and advanced interpretation and geostatistical techniques. The Company has acquired more than 470 square miles of 3-D seismic data in its core geographic areas and plans to acquire an additional 180 square miles of 3-D seismic data in the Gulf Coast within the next nine months. The Company, directly or indirectly, employs or contracts with 33 experienced geologists and geophysicists to develop its projects.
o Consolidate in Core Geographic Areas. The Company is continuing to pursue its consolidation strategy in the D-J Basin, where the Company's net production represents approximately 24% of total D-J Basin natural gas production. By effecting consolidation in the D-J Basin, the Company capitalizes on opportunities for further operating and administrative cost efficiencies and improves its product marketing position through control of increased volumes. HSR will pursue a similar consolidation strategy in various fields and basins within the Mid-Continent area.
o Maintain Low Operating Costs. The Company is an industry leader in operational efficiencies and field management, historically ranking as one of the lowest cost operators in the United States. For the twelve months ended December 31, 1996, the Company's general and administrative expenses were $0.74 per Boe, and its lease operating expenses were $2.32 per Boe. During 1995, HSR's general and administrative expenses were $0.80 per Boe, and its lease operating expenses were $1.95 per Boe. The Company will continue to pursue efficient operations, although expenses are expected to increase modestly due to the differences in the mix of the Company's properties resulting from the Merger and the Company's Gulf Coast activities.
o Capture Downstream Value. The Company seeks to enhance both its margins and operating flexibility through its marketing, trading and transportation business. HSR is one of the most active natural gas producer/marketers in the Colorado Front Range area (the area from Denver north to Fort Collins and south to Colorado Springs) and directly markets approximately 60% of its D-J Basin natural gas production. A significant portion of this production is sold directly to over 400 commercial and industrial end users. In the Mid-Continent area, the Company markets its own natural gas production and also purchases third party natural gas for resale. The Colorado Front Range and Mid-Continent marketing and trading operations are fully integrated, thus providing opportunities for HSR to improve product prices and profit from market imbalances and trading opportunities between the two regions and to capitalize on the combined expertise of the two groups.
o Maximize Financial Flexibility. The Company is committed to maintaining substantial financial flexibility. In funding its growth, HSR has employed a broad array of financing structures, divestitures and asset monetizations. Management currently expects its 1997 capital expenditure budget to be fully funded by internally-generated cash flow. Since the consummation of the Merger and the Acquisitions, the Company has been monetizing certain non-strategic properties with the proceeds reducing outstanding borrowings under the Chase Facility. To date approximately $20 million of such monetization has occurred.
RECENT DEVELOPMENTS
Basin Property Acquisitions
In March and June of 1996, the Company completed the Acquisitions, acquiring all of Basin's D-J Basin properties for aggregate cash consideration of $125.5 million. The Acquisitions included a total of 850 gross wells which at December 31, 1995, had approximately 35 MMBoe of net proved reserves and approximately 5,500 Boe of net daily production. The Acquisitions also included
approximately 250 potential development drillsites. The acquired properties are in the immediate vicinity of HSR's existing D-J Basin operations, and HSR has integrated these assets into its property base with no material increase in overhead, resulting in a substantial decrease in general and administrative costs per Boe of production. In addition to the improved economics associated with consolidation, HSR increased its control of natural gas volumes in the D-J Basin, strengthening the Company's active Colorado Front Range natural gas marketing activities. The Company believes that there remain significant future exploitation and infill drilling opportunities to further develop existing reserves in the D-J Basin through the application of developing technologies, including directional drilling applications. See "Item 2.
Item 2. PROPERTIES
OIL AND GAS PROPERTIES
The following table summarizes certain information with respect to each of the Company's areas of operations and production. All information is presented as of December 31, 1996.
(1) Calculated for the quarter ended December 31, 1996.
(2) Includes leasehold, option and seismic rights.
Denver-Julesburg Basin
The D-J Basin is located in Northeastern Colorado, and over recent years has been the Company's primary producing region. HSR's D-J Basin production and reserves are largely contained in the Codell and Niobrara formations, with additional production from the deeper D-Sand, J-Sand and Dakota sandstones and the shallower Sussex and Shannon sandstones. Drilling success rates have historically been high, and production from these formations is characterized by strong initial flows and long-lived reserves. Production also tends to be a combination of oil and natural gas. Natural gas produced in the central part of the D-J Basin, including the Wattenberg Field area ("Wattenberg"), has an energy content of approximately 1,250 Btu per Mcf, which enhances wellhead value.
One of the attractive features of D-J Basin geology is its multi-pay potential. In a section only 3,500 feet thick, there are at least seven major potentially productive formations. Three of the formations, the Codell, Niobrara and J- Sand, are "blanket" zones in the area of the Company's Wattenberg holdings, while others, such as the D-Sand and the shallower Shannon and Sussex, are more localized.
Wattenberg Field Area. The majority of the Company's D-J Basin properties are concentrated in Wattenberg, located approximately 35 miles north of Denver. The primary geologic objectives of the Company's Wattenberg activities are the Codell and Niobrara formations, found at depths ranging from 6,400 to 7,700 feet. Codell/Niobrara wells usually take five to six days to drill and are typically brought into production within 20 days from commencement of drilling. The generally predictable, quick and trouble-free drilling characteristics of these wells allow multiple-well, multiple-rig development drilling programs to be conducted efficiently. Codell/Niobrara wells typically produce approximately 50% of their reserves in the first three to five years. The remaining
reserves are recovered at a declining rate over the next 15 to 20 years. The Codell and Niobrara formations produce both oil and natural gas, with reserves generally being approximately 70% natural gas and 30% oil.
Greater D-J Basin. The Greater D-J Basin is that portion of the D-J Basin located generally south and east of Wattenberg. Production in the Greater D-J Basin is generally found in D-Sand and J-Sand channels, and can produce oil, natural gas or both. Within the D-Sand and J-Sand, high porosities and permeabilities can yield higher flow rates than Codell and Niobrara wells. D-Sand and J-Sand channels, while not "blanket" formations in the Greater D-J Basin, can be prolific when encountered. The D-Sand and J-Sand are stratigraphically located below the Codell and Niobrara formations at depths ranging from 6,800 to 7,800 feet.
Mid-Continent
The Company's Mid-Continent properties are primarily located in four geological areas (i) the Anadarko Basin in western Oklahoma and the Texas panhandle, (ii) the Arkoma Basin in southeastern Oklahoma and western Arkansas, (iii) southern Oklahoma and (iv) southeast New Mexico and south and east Texas.
Anadarko Basin. The Anadarko Basin is a major Mid-Continent oil and natural gas producing area located in western Oklahoma and the Texas panhandle. The greatest concentration of oil fields occurs on the eastern flank of the basin, with natural gas fields dominating the shelf to the west, the Texas panhandle area and the deep basin located in southwestern Oklahoma. The majority of the Company's production comes from the Red Fork, Springer-Morrow, Chester, Mississippi and Hunton geological formations. Oil and natural gas are produced in this basin from depths of only a few hundred feet to over 20,000 feet, and most of the Company's wells produce from depths between 6,000 and 16,000 feet.
Arkoma Basin. The Arkoma Basin is a crescent-shaped region straddling the Arkansas-Oklahoma border. The Arkoma Basin is a major natural gas region, with most wells producing from depths between 5,000 and 12,000 feet. The majority of the Company's production comes from the Booch, Hartshorne, Atoka, Spiro and Cromwell geological formations, primarily at depths between 5,000 and 10,000 feet.
South Oklahoma. The southern Oklahoma area is a faulted and folded geologic province that extends across seven counties in south-central Oklahoma. The Company's production is mainly from Pennsylvanian Hoxbar, Deese and Springer sands, the Hunton and Viola carbonates, and the Simpson sand. The Company's wells in this region produce from depths ranging from 5,000 to 17,000 feet.
New Mexico/Texas. In these areas, the Company's properties are found principally in the Delaware Basin and south and east Texas. These geologic areas are oil prone and are comprised of numerous stratigraphic and faulted sandstone reservoirs. The Company's Delaware Basin properties are located in New Mexico, with most of its oil production coming from the Delaware formation at depths of 4,000 to 6,000 feet. Natural gas production is principally from the Abo formation at depths of 4,000 to 5,000 feet. The East Texas Basin properties are located in Houston, Freestone, Cherokee and Henderson Counties in Texas and DeSoto Parish in Louisiana. The predominant
reservoirs are normally pressured Cretaceous sandstones and carbonates at depths ranging from 5,000 to 11,000 feet. The Company produces mostly natural gas from the Woodbine, Glen Rose, Rodessa, Pettet and Hosston reservoirs.
Gulf Coast
The Company has established a core geographic area in the on-shore Gulf Coast area of south Texas and Louisiana primarily through two joint ventures, SouthTech and Chenier. Both joint ventures are staffed with explorationists who are experienced in the integration of interpretive geology and advanced 3-D seismic techniques. The Company's Gulf Coast activities focus on both shallow exploitation and deeper exploration targets in the on-shore areas of South Louisiana and the upper Texas Gulf Coast. Focus areas of SouthTech are Acadia, Jefferson Davis and Calcasieu Parishes of South Louisiana and Chambers County in the upper Texas Gulf Coast. The primary focus areas of Chenier are Saint Landry and Evangeline Parishes of Louisiana. Wells in the area target the Frio, Vicksburg, Cockfield, Sparta and Wilcox formations at depths ranging from 1,500 to 11,500 feet. The complex faulted and prolific salt dome dominated region possesses more than 20 reservoir targets that, in various combinations, provide attractive multi-zone drilling prospects from as shallow as 6,500 feet to deeper than 12,000 feet.
Northern Rocky Mountains
HSR produces in two areas of the Northern Rocky Mountains, the Williston and Green River Basins. The Company operates wells in two fields in the Daniels County, Montana portion of the Williston Basin. These wells produce from the Ratcliffe, McGowan and Mission Canyon formations at depths ranging from 5,900 to 6,500 feet. The Company operates 18 wells in the Blue Forest Unit on the Moxa Arch portion of the Green River Basin in Wyoming. The Blue Forest Unit currently produces from the Frontier and Muddy formations found at depths ranging from 10,500 to 11,000 feet. Although most of HSR's natural gas production in Blue Forest Unit has been sold under the TCW Facility, the Company has retained development, operating and certain marketing rights.
PROJECT INVENTORY
The following table summarizes the Company's inventory of projects identified on its properties as of December 31, 1996.
Denver-Julesburg Basin Projects
The Company has a significant inventory of investment opportunities in the D-J Basin. That inventory consists of development drilling on existing spacing, behind-pipe recompletions, potential increased density drilling, wellbore extensions, high angle drilling and exploration leads.
Wattenberg Field Area. While Wattenberg has experienced high levels of development activity in recent years, management believes significant untapped reserves remain. HSR has, in its inventory, 890 development drillsites, of which 663 are included in proved undeveloped reserves. In addition, the Company has identified approximately 391 recompletion opportunities in Wattenberg.
A more significant opportunity may exist in the potential for increased density or infill drilling in the Codell and Niobrara formations within Wattenberg. HSR has undertaken a rigorous analysis to determine the potential for recovery of additional economic reserves through increased density drilling. This study included extensive computer simulation to model the producing characteristics of the formations as well as a pilot field program of drilling, completion and production. The initial conclusions of the feasibility study indicate that there is significant potential to recover additional reserves at reduced costs, both within currently producing fault blocks and by tapping fault blocks that are isolated from existing wellbores, thereby minimizing surface disturbance. Five lateral test wells have been successfully drilled and cased and are producing from existing wellbores. Five additional pilot wells were drilled during the fourth quarter of 1996 and are being evaluated. The Company estimates that there are at least 750 potentially economic infill drillsites on its Wattenberg acreage.
Finally, management believes that substantial opportunities may exist to tap additional reserves through existing wellbore extensions and high angle drilling. The Company is conducting studies to evaluate these applications.
Greater D-J Basin. The Greater D-J Basin, in which the Company owns rights to more than 194,000 gross undeveloped acres, provides HSR with significant exploitation and exploration potential through the use of advanced technologies such as 3-D seismic continuity processing and geostatistical analysis. To date, the Company has drilled 449 wells in the area, with an estimated 8.6 MMBoe of proved reserves, and has 22 active prospects and leads under refinement by geotechnical staff. Geostatistical analysis using seismic responses shows significant promise in helping not only to reduce dry-hole risk, but to also target wells at optimal locations. Recently the Company has drilled three successful wells in its last three attempts. Using advanced 3-D seismic interpretation techniques, the Cervi-Federal #6-29, (producing 100 BOPD and 90 MCFPD), the Cervi-Federal #10-29, (producing 130 BOPD and 35 MCFPD), and the Shoeneman #1-24, (which had an initial production of 110 BOPD, has been successfully fracture treated and is currently producing at rates of 450 BOPD and 300 MCFPD) have all been successful.
Mid-Continent Projects
Prior to the Merger, Tide West had established a reputation as an excellent acquirer and efficient operator of oil and natural gas properties in the Mid-Continent region, though it was not focused on aggressive geotechnical exploitation of its properties. Tide West owned interests in approximately 75 fields located in several Mid-Continent basins. In the Company's opinion, this presents an
opportunity to apply its expertise to prove-up and produce new reserves from the Tide West properties. HSR has added geological and geophysical staff to the Mid-Continent district and has begun the process of high-grading opportunities identified at the time of the Merger and applying technology to uncover new opportunities. The Company has drilled six wells since the Merger, all of which were successfully completed, and has performed a number of successful recompletions.
The Company has outlined an extensive inventory of exploitation and exploration projects in the Mid-Continent region, many of which have been identified in the limited time since the Merger. At the present time, HSR has identified over 200 potential development and exploitation drilling opportunities and 84 recompletion opportunities on its primary focus list. The following are a few examples of such opportunities.
In the Anadarko Basin, the Company owns interests in 804 wells in numerous fields, including Mocane-Laverne, Bivins Ranch, Bishop and Watonga, each of which provides potentially attractive exploitation opportunities. The Company has identified approximately 51 drilling opportunities and 30 recompletions in these four fields. Further work is under way, including processing of 13 square miles of 3-D seismic data on Bivins Ranch, which the Company anticipates will lead to additional activity in these areas.
In the Arkoma Basin, the Company owns interest in 205 wells in Kinta, Bokoshe, Russellville and other fields. In those three fields alone, the Company has identified approximately 129 drilling and 22 recompletion opportunities.
Other areas present additional opportunities. For example, with the use of 3-D seismic, the Company has identified further drilling opportunities at La Reforma Field in northwestern Hidalgo County, Texas, where the Company owns interests in a 5,100 acre contiguous block.
Gulf Coast Projects
Through SouthTech and Chenier, the Company has assembled a growing inventory of both exploitation and exploration projects. These joint ventures have 16 active major project areas and are aggressively pursuing others. Six large 3-D seismic surveys have been acquired, four additional surveys are planned and all are being integrated into extensive subsurface mapping.
SouthTech has assembled seismic rights, options and leasehold interests in approximately 90,000 gross undeveloped acres and intends to expand this position in 1997. SouthTech also has acquired over 140 square miles of 3-D seismic data and has identified approximately 60 exploration prospects and leads. Chenier has assembled seismic rights, options and leases in approximately 23,000 gross undeveloped acres. South Devillier prospect is typical of the opportunities available to the Company through SouthTech and Chenier. South Devillier is the first of the Company's Gulf Coast project areas to be imaged by advanced 3-D seismic technology and fully interpreted. This interpretation has allowed the Company to image several untested prospective fault blocks within a known productive fairway of the Vicksburg Lox "B" sandstone. The first well drilled by HSR based on the South Devillier 3-D interpretation encountered the Lox "B" as anticipated, although the well is not capable of production in paying quantities. HSR's second well on this shoot, the Cooper #2, encountered 33' of reservoir quality Lox "B" sandstone in an adjacent, untested fault block. Pipe has been set on this well and HSR is currently waiting on completion operations to
commence. Based on the 3-D interpretation, there could be as many as 12 additional exploration opportunities on South Devillier alone.
The Company anticipates similar opportunities on many of its other Gulf Coast projects. On the Roanoke 3-D survey, HSR's first test, the Kratzer #1, has encountered approximately 95' of apparent pay in 8 different zones of the Frio. Intermediate casing has been set to protect these zones, while the well is drilled deeper to test a high pressure Hackberry formation prospect, based on the 3-D seismic.
Management believes that its expanding Gulf Coast activities will generate a substantial inventory of exploitation and exploration opportunities in 1997 and beyond.
Northern Rocky Mountain Projects
The Company has a significant inventory of undeveloped acreage and 3-D seismic data in the northern Rocky Mountain area. In the Williston Basin, HSR has approximately 344,000 gross (186,000 net) undeveloped acres and nearly 150 square miles of 3-D seismic data. In the Sand Wash Basin the Company has approximately 123,000 gross (49,000 net) undeveloped acres and has entered into agreements with two major oil companies that include 3-D seismic survey commitments (18 square miles of which have been recently acquired) and options to spend exploration capital on additional 3-D seismic surveys and exploratory wells over the next 18 months. HSR also has approximately 84,000 gross (57,000 net) undeveloped acres in the Greater Green River Basin. The combination of large acreage positions, high-quality reservoirs, 3-D seismic and geostatistical applications and, with respect to the Williston Basin, horizontal drilling, gives HSR exposure to significant potential in the Rocky Mountain area.
ACREAGE
The Company's acreage positions have increased significantly, from approximately 9,000 developed and 37,000 undeveloped net acres as of December 31, 1991 to approximately 327,000 developed and 721,000 undeveloped net acres as of December 31, 1996.
The following table sets forth the gross and net developed and undeveloped acres on which the Company owns the rights to conduct exploration and development activity as of December 31, 1996.
(1) Includes acres upon which the Company owns the rights to conduct seismic, exploration and development activity but is not the lessee.
OIL AND GAS RESERVES
Two independent petroleum engineering consulting firms were engaged to review the Company's estimates of its proved reserves, projected future production and estimated future net revenues from production of proved reserves as of December 31, 1996. Williamson Petroleum Consultants, Inc. reviewed HSR's DJ Basin, Northern Rockies and Gulf Coast properties, and Netherland, Sewell & Associates, Inc. reviewed the Company's Mid-Continent reserves. Such estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data provided by or available to the Company. In determining the estimates of the reserve quantities that are economically recoverable, the Company used selling prices and estimated development and production costs which were in effect as of December 31, 1996. In accordance with guidelines promulgated by the Securities and Exchange Commission, no price or cost escalation or de-escalation was considered. The following table sets forth information as of December 31, 1996, derived from the Company's reserve reports. The present value (discounted at 10%) of estimated future net revenues before income taxes shown in the table is not intended to represent the current market value of the estimated oil and gas reserves owned by the Company. In the aggregate, 78.4% of the Company's total reserves were reviewed by the two engineering firms.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. The reserve data set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. Furthermore, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including prices, future production levels and cost, that may not prove over time to have been correct.
Predictions about prices and future production levels are subject to great uncertainty, and this is particularly true as to proved undeveloped reserves, which are inherently less certain than proved developed reserves, and which comprise a significant portion of the Company's proved reserves.
Pricing assumptions materially affect the calculation of present value of future net revenues, principally in two ways. First, higher or lower prices directly affect estimated cash flows attributable to a given reserve and production stream. Second, higher or lower prices also increase or decrease the number of potentially recoverable barrels of oil or cubic feet of gas. This is because wells reach their economic limit earlier in a lower product price environment than in a higher price environment, hence truncating the economic recovery of reserves.
Oil and gas prices have fluctuated widely in recent years. The weighted average sales prices utilized for the purposes of estimating the Company's proved reserves and future net revenue therefrom at December 31, 1996, were $24.92 per Bbl of oil and $3.39 per Mcf of gas. Oil and gas prices as of the date of this 10-K Report are significantly lower than the 1996 year end prices used in the foregoing Securities and Exchange Commission analysis. For cautions regarding forward- looking statements made or implied by the Company see Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations--Disclosure Regarding Forward-Looking Statements."
For further information concerning the present value of future net revenue from the Company's proved reserves, see Note 15 of the Notes to Consolidated Financial Statements.
Since December 31, 1990, as an operator of domestic oil and gas properties, the Company has filed Department of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by Public Law 93-275. There are differences between the reserves as reported on Form EIA-23 and as reported herein. The difference is attributable to the fact that Form EIA-23 requires that an operator report on the total reserves attributable to wells which are operated by it, without regard to ownership (i.e., reserves are reported on a gross operated basis, rather that on a net interest basis), while reserves reported herein are net to the Company.
DRILLING ACTIVITY
The following table sets forth the net wells drilled and completed by the Company during the periods indicated. Substantially all of the Company's wells produce both oil and gas.
PRODUCTIVE OIL AND GAS WELLS
The number of productive oil and gas wells, operated and non-operated, in which the Company had an interest as of December 31, 1996, are as follows:
Wells are classified as oil or gas producers as described in statutory definitions based on oil/gas ratios. As a result, most of the Company's wells are categorized as oil wells, even though, on an equivalent Btu basis, such wells tend to produce more gas than oil.
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth certain information regarding the costs incurred by the Company in its development, exploration and acquisition activities during the periods indicated.
PRODUCTION
The following table sets forth the Company's oil and gas production data during the periods indicated.
(1) Average daily production for 1996 was calculated for the quarter ended December 31, 1996, as these results are believed to be more indicative of current performance.
Item 3.
Item 3. LEGAL PROCEEDINGS AND ENVIRONMENTAL ISSUES
Litigation. At this time, the Company is involved in no material litigation, however, the Company is involved in various claims and lawsuits incidental to its business.
Environmental Proceedings. The owner of an oil field waste disposal facility, a major oil company and the Company were named as respondents by the United States Environmental Protection Agency ("EPA") in an administrative order brought by the EPA against Weld County Waste Disposal, Inc. ("WCWDI") under section 7003 of the Resource Conservation and Recovery Act ("RCRA") on May 11, 1995. WCWDI operated and continues to own an evaporation pit in Colorado for the disposal of non-hazardous production wastes. The EPA order requires that work be performed to abate a perceived endangerment to wildlife, the environment or public welfare. The Company and other non-operator respondents are working together with the EPA to develop plans and characterization studies, and have caused the facility to be permanently closed.
The Company has utilized this facility in past years to dispose of its production and flowback water. During the period of its use, the Company believed that the facility was operating in compliance with all applicable legal requirements and, along with other oil and gas operators, paid a fee to WCWDI for using this disposal facility. There were a number of other significant contributors to the facility during the period reviewed by the EPA (1988 through 1994) and additional contributors during the period from 1977, when it was constructed, through 1988. The Company and the major oil company were named because they were deemed the major
contributors of waste volumes to the facility for the period reviewed by the EPA. Certain other contributors are participating in their share of the reclamation costs.
Based on the Company's current knowledge and its expectation of proportionate reimbursement from other parties who utilized the facility, the Company does not believe that its share of the reclamation costs will have a material impact on its financial condition or results of operations. By agreement with other contributing parties, the Company is currently paying approximately 50% of the costs associated with the project, but after recovery from additional liable parties, the Company's percentage share of overall costs may be reduced to as low as 40%. The Company has spent approximately $460,000 on its behalf to date on the project. The Company's share of total costs associated with the project, at the 50% level of participation, are currently estimated to range from $1 to $2 million over three years. The full amount of the Company's estimated liability is reflected in the December 31, 1996 financial statements. See Note 2 of Notes to Consolidated Financial Statements.
Item 4.
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
The Company's common stock (NYSE symbol "HSE") began trading publicly on the NYSE effective June 22, 1994. Prior to that, the Company was traded on the NASDAQ National Market System under the symbol "HSRS" effective November 24, 1992. There was no public market for the common stock before November 24, 1992. The following table presents the high and low sales prices reported by the NASDAQ and NYSE for the periods indicated. These prices do not include retail markups, markdowns or commissions.
As of December 31, 1996, there were 449 holders of record of the common stock.
The Company has never paid any cash dividends on its common stock, and the Board of Directors of the Company does not currently intend to declare cash dividends on its common stock. The Company instead intends to retain its earnings to support the growth of the Company's business. Any future cash dividends would depend on future earnings, capital requirements and the Company's financial condition and other factors deemed relevant by the Board of Directors. The Company's credit facility currently prohibits payment of dividends and the indentures governing its outstanding 9 1/4% and 9 7/8% senior subordinated notes due in 2006 and 2003, respectively also limit the Company's ability to pay dividends.
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. See also, Management's Discussion and Analysis of Financial Condition and Results of Operations.
(In thousands, except per share amounts and average prices) For the Years Ended December 31,
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL Over the past 12 months, the Company has undertaken several strategic initiatives that have positioned the Company for a period of significant growth in reserves, production, cash flow and earnings. In 1995, the Company articulated a strategy that included (i) consolidating in its core geographic areas, particularly the D-J Basin, (ii) diversifying its asset base outside of the D-J Basin, (iii) capturing more of the value stream by marketing its production and (iv) maximizing its financial flexibility. By completing the Acquisitions and the Merger and by forming two important, exploration-focused Gulf Coast joint ventures, SouthTech and Chenier, HSR has taken the fundamental initial steps to implement its strategy. Management's focus for the foreseeable future will be to continue to execute this strategy with particular emphasis on activities that maximize the financial returns from HSR's expanded asset base.
The Company now has three significant core areas of operations, the geologic and geographic diversity of which combine to create an oil and natural gas company with attractive, long-lived reserves balanced with meaningful exposure to exploration and technologically-driven upside. The Company has also created a strategically important and profitable presence in the natural gas marketing, trading and transportation business, which provides the opportunity for the Company to increase its operating margins on production from both the D-J Basin and Mid-Continent areas and has begun an oil trading and transportation business to be engaged in the purchase, sale and transport of crude oil.
The United States oil and gas industry is subject to large variations in profitability due in part, to fluctuating commodity prices and related changes in rates of reinvestment by industry participants. Over the past year the industry has seen increases in both oil and natural gas prices from the relatively low price levels experienced in 1995. Several factors have lead to a positive fundamental outlook for the oil and gas industry and improved economics for production in the Company's core geographic areas. These include (i) low natural gas storage levels combined with relatively high wellhead capacity utilization, (ii) increasing overall natural gas demand, (iii) deregulation of distribution and marketing channels, particularly for D-J Basin and Rocky Mountain production, and expansion of pipeline capacity to transfer gas to markets outside the Colorado Front Range and (iv) successful application of advanced oil and natural gas exploration, drilling and production technologies. Since the end of 1996, oil and natural gas prices have decreased in certain areas of the country, in part due to weather conditions.
NATURAL GAS PRICE CONSIDERATIONS Approximately 76% of the Company's proved producing reserves consist of natural gas located in the D-J Basin and Mid-Continent areas. The absolute level and volatility of natural gas prices have a material impact on the Company.
During 1995 and early 1996, prices for Rocky Mountain natural gas were substantially below prices for natural gas in markets outside the Rocky Mountain region. This disparity was caused by low demand for Rocky Mountain gas due to an unusually warm winter season and above-normal availability of hydro-electric power in the western United States. This resulted in excess natural gas supply in the Rocky Mountains which led to downward price pressure in the Colorado Front Range market. However, through the end of 1996, the market for the Company's
D-J Basin natural gas had strengthened substantially due to several factors. First, the excess supply from Wyoming natural gas producers has declined as a result of increased demand from West Coast markets. Second, in October 1995, the Colorado Public Utilities Commission approved tariff changes that effectively eliminated transportation costs for D- J Basin natural gas sold to the Colorado Front Range market, resulting in an approximately $0.40 per MMBtu transportation cost advantage for D-J Basin producers. Third, the supply of D-J Basin natural gas has declined over the last two years due to reduced drilling in the D-J Basin and natural production declines. The average natural gas price received by the Company for its D-J Basin production has increased from $1.28 per Mcf in 1995 to $1.90 per Mcf in 1996. In addition, expansion of pipeline capacity has begun, which will, in mid-to-late 1997, provide additional transportation outlets for Wyoming producers to markets other than the Colorado Front Range. The Company believes that these developments will further reduce the disparity between D-J Basin pricing and pricing generally available elsewhere in the United States.
The D-J Basin provides a significant portion of the Company's natural gas production. Historically, the price of D-J Basin natural gas (on a Btu-equivalent basis) has been linked closely to the Colorado Interstate Gas pipeline ("CIG") Rocky Mountain Index. However, more recently, as a result of the tariff changes and the seasonal nature of demand in the Colorado Front Range, the price for D-J Basin natural gas tends to reflect the CIG Rocky Mountain Index during the low demand summer months (generally April through October) and Mid-Continent indices during the high demand winter periods (generally November through March).
Gas prices in the Mid-Continent are closely tied to established indices which are influenced by national supply and demand factors. Average natural gas prices received by the Company in the Mid-Continent generally fluctuate with changes in Mid-Continent posted prices, which for the years 1993 through 1996 averaged $0.25 per MMbtu less than the Henry Hub price. The average natural gas price received in the Mid-Continent since the Merger in June 1996 through December 31, 1996, was $2.24 per Mcf, or $0.29 below the Henry Hub price (before hedging).
OIL PRICE CONSIDERATIONS Oil prices are established in a highly liquid international market. Average oil prices received by the Company in the D-J Basin and Mid-Continent generally fluctuate with changes in the NYMEX West Texas Intermediate ("NYMEX-WTI") crude oil closing prices. The Company's average oil price for 1995 was approximately $1.77 per Bbl below NYMEX-WTI closing prices. The average oil price for 1996 was approximately $0.45 below NYMEX-WTI closing prices. The increase in the relative value of the Company's oil production during 1996 is a result of renegotiation of several oil sales contracts, as well as the general increase in the market value of the Company's D-J Basin oil production.
RESULTS OF OPERATIONS During 1996 the Company continued drilling and development activity in the D-J Basin and completed the Merger and the Acquisitions. At December 31, 1996, the Company owned interests in more than 3,500 producing wells (of which it operated more than 2,600) compared to 1,300 wells (of which it operated more than 1,100) at December 31, 1995. The Company's results of operations have been significantly affected by the Acquisitions, the Merger and its drilling program. Fluctuations in oil and natural gas prices have also significantly affected the Company's results.
COMPARISON OF YEARS ENDED DECEMBER 31, 1996 AND 1995
OIL AND GAS REVENUES For the comparative periods, oil production increased from 1,582 MBbls to 1,923 MBbls and gas production increased from 21,049 MMcf to 34,163 MMcf, or 22% and 62%, respectively. Average oil prices realized increased by 27% from $16.52 to $20.90 per Bbl and average gas prices realized increased by 51% from $1.30 to $1.96 per Mcf. The production increases were the result of additional production from the properties acquired in the Acquisitions and the Merger and new wells drilled by the Company. The net effect of these changes resulted in an increase in oil and gas revenues from $53.4 million to $107.3 million or 101%. The Company also recognized $2.7 million in other gas revenues from the sale of tax credits with respect to its Section 29 tax credit agreements for the year ended December 31, 1996, as discussed in Note 12 of the Notes to Consolidated Financial Statements.
The Company, through its gas marketing division and its wholly owned subsidiary, TWTT, actively markets a portion of its own natural gas production, markets natural gas to third parties and supplies natural gas to end-users. Trading and transportation net margins were $673,553 at December 31, 1996. There were no comparable revenues in 1995.
INTEREST INCOME AND OTHER INCOME Interest and other income increased by $418,557, or 256%, for the year ended December 31, 1996. The increase in interest and other income was mainly due to short term investing of the Company's available funds, as well as a gain recorded on the sale of assets of $118,649.
PRODUCTION EXPENSES Lease operating expenses increased by $7,755,693, or 78%, due to an increase in the number of producing wells. On a Boe basis, lease operating expenses increased from $1.95 to $2.32 for the comparative periods. This increase is primarily the result of a different mix of wells in the current year, including wells with historically higher operating costs which were acquired as a result of the Acquisitions. Production taxes increased by $4,144,906, or 102%, due to increased production and prices. Production taxes in 1996 reflect an adjustment for a reduction in the Company's severance tax rate. A cumulative rate adjustment for 1995 was recorded in the third quarter of 1995.
DEPRECIATION, DEPLETION AND AMORTIZATION Depreciation, depletion and amortization ("DD&A"), a non-cash expense, increased $15,725,997, or 59%, due to an increase in production and an increase in the depletion rate. For the year ended December 31, 1996, the Company had a weighted depletion rate of $5.33 per Boe ($5.41 for the quarter end December 31, 1996). The Company adjusts its DD&A rate based on material changes in its reserves and on an annual basis based on year end engineering.
GENERAL AND ADMINISTRATIVE EXPENSE General and administrative expense reflects costs incurred net of administrative costs directly attributable to drilling and well operations, which costs are included in lease operating expenses or are capitalized. General and administrative expenses increased $1,566,812, or 38%. The increase for the comparative periods is primarily attributable to the Merger and retention of the former Tide West employees. On a Boe basis, general and administrative expenses decreased from $0.80 to $0.74 for the comparative periods.
INTEREST EXPENSE Interest expense increased $12,717,285 or 124%, due to increased borrowings on the Company's long-term bank debt. Also, in November 1996, the Company issued $150 million of its 9 1/4% senior subordinated notes due in 2006.
PROVISION FOR INCOME TAXES The Company follows the provisions of Statement of Financial Accounting Standards ("SFAS") No. 109. Pursuant to SFAS 109, the Company has recorded a tax provision based on tax rates in effect during the period. Accordingly, the Company accrued taxes at the rate of 38.1% in 1996 and 1995. Due to significant intangible drilling costs, which are deductible for tax purposes, substantially all of the Company's tax provision in both periods is deferred.
COMPARISON OF YEARS ENDED DECEMBER 31, 1995 AND 1994
OIL AND GAS REVENUES For the comparative periods, oil production decreased from 1,664 MBbls to 1,582 MBbls and gas production increased from 20,108 MMcf to 21,049 MMcf, or 5% and 5%, respectively. The average price of oil increased by 11% from $14.83 to $16.52 per Bbl, and gas prices decreased by 24%, from $1.70 to $1.30 per Mcf. The net effect of these changes resulted in an oil and gas revenue decrease of 9% from $58.8 million to $53.4 million. The Company also recognized $1.8 million in other gas revenues from the sale of tax credits for the year ended December 31, 1995, as discussed in Note 11 and Note 12 of the Notes to Consolidated Financial Statements.
INTEREST AND OTHER INCOME Interest and other income decreased by $75,841 or 32%, for the year ended December 31, 1995. This was due primarily to short term investing of additional funds in the prior year, which were available as a result of the November 1993 offerings. By the end of the second quarter of 1994, the Company's drilling programs absorbed any remaining available funds from those offerings.
PRODUCTION EXPENSES Lease operating expenses increased by $1.6 million or 20%, due to the increase in the number of producing wells. Production taxes, which are a direct result of oil and gas sales, decreased by $1.1 million or 21%, for the period ended December 31, 1995, as a result of the decrease in oil and gas sales, as well as a reduction in the Company's effective severance tax rate.
DEPRECIATION, DEPLETION AND AMORTIZATION Depreciation, depletion and amortization increased by $1.5 million or 6%, for the year ended December 31, 1995, due to an overall increase in production and an increase in the depletion rate from $4.80 per Boe to $4.97 per Boe.
GENERAL AND ADMINISTRATIVE EXPENSES General and administrative expenses reflect costs incurred, net of administrative costs directly attributable to drilling and well operations. Such costs are included in lease operating expenses or are capitalized. General and administrative expenses decreased $152,891 or 4%, for the period ended December 31, 1995. The decrease is due to the increased well-related reimbursements resulting from an increase in the number of wells operated.
INTEREST EXPENSE Interest expense for the period ended December 31, 1995, increased $2.7 million or 36%. The increase is due to increased borrowings on the Company's long-term bank debt.
PROVISION FOR INCOME TAXES Pursuant to SFAS 109, the Company has recorded a tax provision based on tax rates in effect during the period. Accordingly, the Company accrued taxes at the rate of 38.1% in 1995 and 1994. Due to significant intangible drilling costs, which are deductible for tax purposes, all of the Company's tax provision in both periods is deferred.
LIQUIDITY AND CAPITAL RESOURCES
Financing Sources
The Company is committed to reducing its debt to total book capitalization ratio and is currently evaluating various alternatives by which to do so, including asset divestitures. The Company believes that it will be able to arrange a favorable combination of financing alternatives to fund its ongoing capital requirements and reduce its overall financial leverage. Until this debt ratio is reduced, the Company currently plans to fund capital expenditures attributable to exploration and drilling activities primarily out of its expected cash flow from operations. The Company has financed, and expects to continue to finance, its acquisition activities, if any, with (i) cash flow from operations, (ii) borrowings under the Chase Facility (defined below), (iii) public offerings of equity and debt, (iv) divestitures (including asset monetizations) of non-core assets and (v) the TCW Facility (as defined). Borrowings in connection with acquisitions may have the affect of increasing the Company's leverage.
On June 7, 1996, the Company entered into a $180 million revolving and senior bank credit facility with The Chase Manhattan Bank, as agent (the "Chase Facility"). On June 14, 1996, the Company amended the terms of the Chase Facility to increase the maximum credit amount to $350 million. Under the terms of the Chase Facility, no principal payments are required until June 14, 2001, assuming the Company maintains a Borrowing Base sufficient to support the outstanding loan balance. The Borrowing Base is based on the underlying value of the Company's oil and natural gas properties. The Chase Facility bears interest at the Base Rate plus 0% to 0.5% or LIBOR plus 0.75% to 1.5%. As part of the amendment to the Chase Facility, Tide West's senior bank debt in the amount of $39.5 million was fully repaid.
In November 1996, the Company issued $150 million of its 9 1/4% senior subordinated notes due in 2006 (the "Notes"). The offering of the Notes (the "Offering") was undertaken in order to replace a portion of the Company's outstanding indebtedness under the Chase Facility with fixed rate term debt. Upon consummation of the Offering and the application of the estimated net proceeds therefrom, the borrowing base under the Chase Facility was amended to $275 million, resulting in an amount available for borrowing of $101 million at December 31, 1996.
The Notes issued are general, unsecured obligations of the Company, subordinated in right of payment to all existing and any future senior indebtedness of the
Company. The Notes rank pari passu with existing and any future senior subordinated indebtedness (including the Company's 9 7/8% senior subordinated notes) and senior to any future subordinated indebtedness of the Company. The Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured, senior subordinated basis by two of the Company's subsidiaries, Orion Acquisition, Inc. and HSRTW, Inc. (the Subsidiary Guarantors"). There are no significant contractual restrictions on distributions from each of the Subsidiary Guarantors to the Company.
In August 1995, the Company signed a Term Sheet with a Trust Company of the West-related entity covering a proposed $90 million non-recourse, volumetric overriding royalty facility (the "TCW Facility"). The proceeds from the TCW Facility may be used by the Company at its discretion for a variety of corporate purposes, including acquisitions of new properties, exploration and development drilling and monetization of existing corporate properties. Effective July 1996, the Company sold certain non-strategic properties under the TCW Facility for total consideration of $9.4 million. The Company used the sale proceeds to repay indebtedness under the Chase Facility.
The Company anticipates that its available borrowing capacity under the Chase Facility, combined with its operating cash flow and the TCW Facility, provide the Company with the financial resources and flexibility to fund current and ongoing development activities and to meet other financial obligations. Since the consummation of the Merger and the Acquisitions, the Company has monetized $20 million of non-strategic properties (including the TCW sale), using the proceeds to reduce outstanding borrowings under the Chase Facility. The nature of the Company's current development strategies and other activities provide the Company with considerable flexibility in terms of the timing and magnitude of its capital expenditures. If the Company experiences unforeseen changes in its working capital position or capital resources, management may revise the capital expenditure program accordingly or alternatively may supplement the capital position of the Company through, among other things, the issuance of additional equity or debt securities or by entering into joint venture arrangements.
Capital Commitments
For the twelve months ended December 31, 1996, the Company incurred total exploration, development and leasehold capital expenditures of $50.6 million. The Company estimates capital expenditures for 1997 will be approximately $65 million, which will be allocated in varying amounts primarily to activities in the Company's three core geographic areas: the D- J Basin of the Rocky Mountains, the Anadarko and Arkoma Basins of the Mid-Continent and the on-shore Gulf Coast region. The Company continuously evaluates its inventory of drilling opportunities and adjusts the amount and allocation of its capital program based on a number of factors, including seismic results, prospect readiness, product prices, service company availability and rates, acquisitions and capital position.
A major component of the Company's capital expenditure program includes costs associated with the consolidation and development drilling in the D-J Basin, and, to a lesser extent, the development of its other Rocky Mountain properties. In the second quarter of 1996, the Company acquired Basin's D-J Basin properties for a total cash consideration of $125.5 million. The Acquisitions increased the Company's D-J Basin reserves by 35 MMBoe and production by 5,500 Boe per day. The Company also incurred approximately $31.3 million in capital
expenditures in 1996 for drilling and recompleting wells and building gathering systems on the Company's existing Wattenberg Field area properties, compared to $14.9 million in 1995.
The second component of the Company's capital expenditure program is the continued exploitation of the properties acquired as a result of the Merger with Tide West. Since the completion of the Merger in June 1996, the Company has incurred total exploitation and development expenditures in the Mid-Continent area of $4.7 million. The Company is currently evaluating a variety of opportunities that include increased exploitation, exploration and density drilling, recompletions and field extensions.
The final component of the Company's capital expenditure program is to develop exploitation and exploration prospects in the Gulf Coast. As described below, the Company has entered into two joint ventures. In 1996, the Company incurred total capital expenditures of $7.6 million in the Gulf Coast. The Company spent approximately $2.0 million under the SouthTech joint venture in 1995 for seismic, leasehold and overhead costs. In 1996, the Company spent approximately $3.3 million in similar costs and for drilling.
In June 1996, the Company entered into an exploration and development agreement with Chenier Exploration, Inc. ("CEI"), pursuant to which the Company purchased from CEI and a third party interests in properties in the Gulf Coast for approximately $1.9 million, of which $1.2 million was paid in cash and the remaining portion was funded with a promissory note. Under the terms of the agreements, CEI will be responsible for the generation and development of prospects in the project areas. In 1996, the Company spent $2.3 for seismic, leasehold, drilling and overhead costs.
In 1994, the Company entered into an exploration agreement with Union Pacific Resources Company covering drilling locations in the D-J Basin, pursuant to which the Company committed to spend $9.3 million during the two years ended June 1996 and meet certain other minimum obligations. All such commitments have been met. In 1996, the Company elected to extend the agreement and committed to spend approximately $2.4 million by June 1997. The Company has also entered into a number of other standard industry arrangements that require the drilling of wells or other activities. The Company believes that it will meet its obligations under these arrangements, which individually and in the aggregate are not material.
Working Capital and Cash Flow
Working capital at December 31, 1996 was $13.7 million. Net cash provided by operating activities for the year ended December 31, 1996, was $52.3 million, up from $ 31.2 million in the same period in 1995. This increase is primarily the result of increased oil and natural gas production revenues attributable to the larger number of producing wells resulting from its drilling activities and the wells acquired in the Acquisitions and the Merger, as well as higher product prices. Future cash flows will be influenced by, among other factors, the number of producing wells on line, product prices and production constraints.
Risk Management. The Company uses financial instruments to reduce its exposure to market fluctuations in the price and transportation cost of oil and natural gas. The Company's general
strategy is to hedge price and location risk with swap, collar, floor and ceiling arrangements. When utilizing such instruments, the Company strives to hedge its production back to the wellhead, to minimize basis risk. In addition to hedging activities, the Company is engaged in using the financial markets to capture trading margins. The Company has established policies with respect to open positions which limit its exposure to market risk and requires reporting to management of the potential financial exposure on a daily basis resulting from both hedging and trading activities.
Hedging Activities. Activities for hedging purposes are entered into by the Company to manage its exposure to price and location risks in the marketing of its oil and natural gas production and, in the case of its marketing activities, third party natural gas. Gains and losses on hedging positions are deferred and recognized in the period the underlying physical transactions occur in "oil and natural gas sales" and "trading and transportation revenues" (for third party natural gas).
The Company has entered into the following forward sales and swap arrangements with respect to its natural gas production for the quarters indicated below (total average daily natural gas production for the quarter ended December 31, 1996 was 118,930 Mcf/day):
The Company has hedged through collar arrangements approximately two-thirds of its oil production at a floor price of $20.00 and a ceiling price of $24.00 per Bbl through the first quarter of 1997. Additionally, with respect to the hedging of third party natural gas, the Company has hedged 8.6 Bcf through December 1997 with offsetting physical positions at settlement prices which are based upon NYMEX future prices or other published indices.
Trading Activities. The Company engages in the trading of various energy related financial instruments which require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, swap or other contractual arrangement. Activities for trading purposes are accounted for using the mark-to-market method. Under this method, changes in the market value of outstanding financial instruments are recognized as a gain or loss in the period of change on a net basis in "trading and transportation revenues." The market prices used to value these transactions reflect management's best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. The values are adjusted to reflect the potential impact of liquidating the Company's position in an orderly manner over a reasonable period of time under present market conditions.
Company policy requires that financial instrument purchase and sales contracts be balanced in terms of contract volumes and the timing of performance and delivery obligations. As of December 31, 1996, all open positions were balanced with an offsetting position. During 1996, gains of $462,000 were recognized in connection with these activities and are included in "trading and transportation revenues."
Credit Risk While notional amounts are used to express the volume of various derivative financial instruments, the amounts potentially subject to credit risk, in the event of nonperformance by the third parties, are substantially smaller. Counterparties to the swap, collar, floor and ceiling arrangements discussed above are investment grade financial institutions. Accordingly, the Company does not anticipate any material impact to its financial position or results of operations as a result of nonperformance by the third parties on financial instruments related to hedging activities or trading activities.
Interest rate swaps. During the second quarter of 1995, the Company entered into an interest rate exchange agreement with a financial institution to hedge its interest rate on $40 million of the Company's borrowings at 7.76% through May 2002. Under the terms of the agreement, the difference between the Company's fixed rate of 7.76% and the three month LIBOR rate plus 1.125% is received or paid by the Company.
The Company, through the Merger, assumed interest rate exchange agreements with two financial institutions to hedge its interest rate on a total of $40 million of the Company's borrowings at rates ranging from 6.16% to 7.32% for 1997 through 1999. Under the terms of these agreements, the difference between the Company's fixed rate and the three month LIBOR rate is received or paid by the Company.
Contingencies
In May 1995, the Company was named as a respondent by the United States Environmental Protection Agency (the "EPA") in an administrative order brought under the Resource Conservation and Recovery Act ("RCRA") by the EPA against the owner/operator of an oilfield production water evaporation facility. Based on its evaluation of the above matters, and after consideration of reserves established, the Company believes the resolution of such matters will not have a material adverse effect on the Company's financial position or results of operations. See Item 3. "Legal Proceedings--Environmental Issues" and Note 10 to Consolidated Financial Statements.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This 10-K Report includes statements that are not purely historical and are "forward-looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended, including statements regarding the Company's expectations, hopes, beliefs, intentions or strategies regarding the future. All statements other than statements of historical facts included in this 10-K Report, including without limitation, statements under "Business," "Properties," "Legal Proceedings and Environmental Issues" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" regarding reserves and their values, planned capital expenditures, increases in oil and natural gas production, trends or expectations concerning oil and gas prices, the number and prospective nature of anticipated wells to be drilled in 1997 and thereafter, development potential, infill potential, drillsite potential, exploitation and exploration prospects and leads, drilling prospects, consolidation opportunities and the Company's financial position, business strategy and other plans and objectives for future operations, potential liabilities or the expected absence thereof, the potential outcome of environmental matters, litigation or other proceedings, are forward-looking statements. All forward-looking statements included or incorporated by reference in this 10-K Report are based on information available to the Company on the date hereof, and the Company assumes no obligation to update such forward-looking statements. Although the Company believes that the assumptions and expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct or that the Company will take any actions that may presently be planned.
There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. See Item 2. "Properties--Oil and Gas Reserves."
Many factors may affect the Company's expectations and plans. Capital expenditure and financing plans may change in connection with the success of drilling activities, the general availability of capital, interest rates, and cash flow available from operations. Cash flow available from operations may change depending on costs of materials and services, regulatory burdens and commodity prices. Oil and natural gas prices are volatile, and there are several potentially significant adverse effects to the Company which can result if product prices decline materially. First, lower product prices will adversely impact the Company's cash flow and could cause the Company to (i) curtail its capital program, (ii) borrow additional amounts under its revolving credit agreement, or (iii) issue additional debt or equity securities. Second, lower product prices could cause the borrowing base under the Company's bank credit agreement to be reduced and certain covenant tests to be adversely affected. Third, under rules promulgated by the Securities and Exchange Commission, companies that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. Lower product prices adversely impact the ceiling calculation. Should the Company realize sustained lower product prices, it could be required to write down its oil and gas properties, resulting in a non-cash charge against earnings.
Certain additional important factors that could cause actual results to differ materially from the Company's forward looking statements are disclosed under "Business," "Properties," other portions of "Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this 10-K Report and in the Company's 8-K Report filed February 26, 1997. All subsequent written or oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the factors mentioned above.
CERTAIN DEFINITIONS
The terms defined in this section are used throughout this report.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Behind-pipe reserves. Proved reserves in a formation through which production casing has already been set in the wellbore, but from which production has not commenced.
Boe. Barrels of oil equivalent, determined using the ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of crude oil or condensate.
Btu. British thermal unit or units. One Btu is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
COPAS charge. A charge made by the operator of a well for the account of all working interests, the payment of which constitutes reimbursement for the operator's administrative costs attributable to operating the well.
Development location. A location on which a development well can be drilled.
Development well, development drilling. Drilling of a well within the proved area of an oil or gas reservoir to the stratigraphic depth of a horizon known to be productive in an attempt to recover proved undeveloped reserves.
Dry hole. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or gas well.
Estimated future net revenues. Revenues from production of oil and natural gas, net of all production-related taxes, lease operating expenses and capital costs.
Exploitation well or exploitation drilling. Drilling of wells in areas of known production. However, because of geologic, reservoir and other characteristics it is possible that an exploitation well may not encounter commercial quantities of reserves. Therefore such wells carry somewhat greater risk than development drilling. Oil and gas reserves associated with exploitation wells are not typically considered to be proved.
Exploratory well or exploratory drilling. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir beyond existing defined limits.
Farmout. An assignment of an interest in a drilling location and related acreage, typically conditional upon the drilling of a well on that drilling location.
Finding Cost. The capital costs associated with finding and developing oil and natural gas reserves.
Gross acre. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
Held by production. Acreage covered by an oil and gas lease which has a producing well on it, or which is pooled with a lease or leases having one or more producing wells on them, so the lease is maintained in effect for the duration of such production.
Henry Hub. The delivery point of the NYMEX natural gas contract, located in southern Louisiana.
Horizontal drilling. Horizontal drilling involves deviating the angle of a wellbore approximately 90 degrees from vertical to near horizontal in the formation of interest. Horizontal drilling permits the wellbore to contact and intersect a larger portion of the producing horizon than is permitted by conventional vertical drilling techniques and can result in increased production rates and greater ultimate recovery of hydrocarbons.
Hydraulic fracturing. A mechanical technique used to enhance productivity and ultimate reserve recovery. Fluids and a proppant are injected into a particular reservoir at rates and pressure sufficient to create a series of fractures or cracks in that reservoir.
Increased density, or infill, drilling. Somewhat similar to development drilling, increased density drilling involves wells drilled within the proved area of an oil or gas reservoir to a zone known to be productive. However, infill drilling generally involves an increase in well density based on engineering and geological studies which demonstrate that the existing well density does not adequately drain the reservoir.
Lead. An area with respect to which the Company has very preliminary information warranting further geoscientific investigation and analysis with the hope that one or more prospects may be developed.
Lease operating expense. All direct costs associated with and necessary to operate a producing property.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MBoe. One thousand barrels of oil equivalent.
MBtu. One thousand Btus.
Mcf. One thousand cubic feet of natural gas.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
MMBoe. One million barrels of oil equivalent.
MMBtu. One million Btus.
MMcf. One million cubic feet of natural gas.
Multi-pay horizons. A well bore with more than one zone that may potentially produce oil and/or natural gas.
Net acres or net wells. The sum of the working interests owned in gross acres or gross wells.
Present value of estimated future net revenues, pretax present value at constant prices of estimated future net revenues. Estimated future net revenues before income taxes, discounted by a factor of ten percent per annum and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the Commission.
Productive well. A well that is producing or that is capable of producing oil or natural gas.
Prospect. An area with respect to which the Company has geologic and possibly geophysical information and analysis indicating the possible presence of producible hydrocarbons at one or more reasonably focused locations. The term prospect refers to many types of areas with a wide range of completeness of concept, information and analysis but, in any event, is based on more complete information than a lead.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can be drilled consistent with local spacing rules for the purpose of recovering proved reserves.
Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Recompletions. Within an existing wellbore, a recompletion involves completion for production of a formation other than those which have previously been productive. It is the mechanism by which behind-pipe reserves become productive.
Reserve replacement costs. Total costs incurred for exploration and development, divided by reserves added from all sources, including reserve discoveries, extensions and improved recovery additions, net of revisions to reserve estimates and purchases of reserves in place.
Royalty interest, overriding royalty interest. An interest in an oil and natural gas property entitling the owner to a share of oil and natural gas production free of costs of drilling, completion and production.
Tcf. One trillion cubic feet of natural gas.
3-D seismic projects. 3-D seismic projects involve the use of seismic reflections to assist in mapping in three dimensions the structural and stratigraphic aspects of certain reservoirs lending themselves to the application of this advanced technology. Particularly when coupled with advanced processing, interpretation, geostatistical techniques and interpretive geology, this technology can materially reduce the risk associated with some types of drilling.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Waterflood. A waterflood is the injection of water into a reservoir to (i) fill pores vacated by produced fluids or (ii) push hydrocarbons from the injector well to another wellbore from which reserves can be produced. Waterfloods are intended to maintain reservoir pressure, assist production and enhance reservoir recovery rates.
Wattenberg. The geographic region in the D-J Basin located approximately 35 miles north of Denver, where the J-Sand formation is productive, as well as adjacent areas where the Codell, Niobrara, Sussex and Shannon formations are productive.
Wellbore extension. A wellbore extension involves deepening an existing wellbore to a new and deeper formation.
Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and entitles it to ownership of a share of production.
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., a Delaware corporation, (the "Company") was organized in January 1987. The Company, directly or through subsidiaries, acquires, develops, and exploits oil and gas properties. The Company's primary properties are located in the D-J Basin of the Rocky Mountains, the Anadarko and Arkoma Basins of the Mid-Continent and the on-shore Gulf Coast area. The Company, through its gas marketing division and its wholly owned subsidiary, TWTT, actively markets a portion of its own natural gas production, markets natural gas to third parties and supplies natural gas to end-users.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
OIL AND GAS PROPERTIES The Company accounts for its oil and gas activities using the full cost method of accounting. Under the full cost method of accounting, all costs of exploration for and development of oil and gas reserves, including costs of surrendered and abandoned leaseholds, delay lease rentals, dry hole costs, geological and geophysical costs and direct overhead related to exploration and development activities are capitalized. Payroll and other internal costs capitalized include salaries and related fringe benefits paid to employees directly engaged in the acquisition, exploration, and development of oil and gas properties, as well as all other directly identifiable internal costs associated with these activities, such as rentals, utilities, and insurance. Payroll and other internal costs associated with production, operation, and general corporate activities are expensed in the period incurred. Future development, site restoration, dismantlement, and abandonment costs, net of salvage values, are estimated on a property- by-property basis based on prevailing prices and are amortized to expense, along with the capitalized costs discussed above, using the unit-of-production method based upon production and estimates of proved reserve quantities. Accumulated depreciation, depletion, and amortization is recorded on the balance sheets as a reduction to property, plant, and equipment costs. No gains or losses are recognized upon the sale or other disposition of oil and gas properties unless a significant portion of the reserves are sold.
Capitalized costs associated with undeveloped properties are excluded from amortization until a determination has been made as to the existence of proved reserves or an impairment has occurred. At December 31, 1996 and 1995, the Company excluded costs aggregating $54,709,553 and $26,778,702, respectively, from capitalized costs being amortized. Of the costs excluded at December 31, 1996, $34,203,488 were incurred in 1996, $5,879,125 in 1995, $12,371,811 in 1994, $1,957,038 in 1993, and $298,091 in 1990. The Company capitalizes interest related to its undeveloped properties. During 1996, 1995, and 1994, the Company capitalized $3,259,053, $2,001,436, and $1,852,633 of interest, respectively.
Net capitalized costs of oil and gas properties less related deferred income taxes may not exceed an amount equal to the present value discounted at 10% of estimated future net revenue from proved oil and gas reserves plus the lower of costs or estimated fair market value of unproved properties (the "full cost ceiling"). Should capitalized costs exceed the full cost ceiling, an impairment would be provided. The full cost ceiling may be particularly sensitive to changes in the near term in pricing
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
and production rates. The above limitation is applied on a quarterly basis using current prices at the end of the quarter.
INCOME TAXES The Company follows the liability method of accounting for income taxes as prescribed by SFAS 109. Accordingly, deferred tax provisions or benefits are recognized in the financial statements for the change in deferred tax liabilities or assets during each year. The deferred liabilities or assets represent taxes payable or refundable in future years, as measured by the provisions of enacted tax laws, or as a result of temporary differences between the bases of assets and liabilities for financial reporting and tax reporting purposes. Such differences relate mainly to depreciable and depletable properties and intangible drilling costs.
CASH EQUIVALENTS Cash and cash equivalents include cash on hand, amounts held in banks and highly liquid investments purchased with an original maturity of three months or less.
FINANCIAL INSTRUMENTS The Company engages in price and location risk management activities for both hedging and trading purposes. Activities for hedging purposes are entered into by the Company to manage its exposure to price and location risks in the marketing of its oil and natural gas production and, in the case of its marketing activities, third party natural gas. Gains and losses on hedging positions are deferred and recognized in the period the underlying physical transactions occur in "oil and natural gas sales" and "trading and transportation revenues" (for third party natural gas). Activities for trading purposes are accounted for using the mark-to-market method. Under this method, changes in the market value of outstanding financial instruments are recognized as a gain or loss in the period of change on a net basis in "trading and transportation revenues." The market prices used to value these transactions reflect management's best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. The values are adjusted to reflect the potential impact of liquidating the Company's position in an orderly manner over a reasonable period of time under present market conditions.
EARNINGS PER SHARE Earnings per share is computed based on the weighted average number of common shares actually outstanding plus the shares that would be outstanding assuming exercise of dilutive stock options and warrants, which are considered to be common stock equivalents. The number of shares that would be issued from the assumed exercise of stock options and warrants has been reduced by the number of shares that could have been repurchased from the proceeds at the assumed fair market value price of the Company's stock.
ACCRUED AD VALOREM TAXES The Company considers ad valorem taxes payable within one year to be current. Other ad valorem taxes are classified as non-current because the required payment dates are not within one year.
DEFERRED CHARGES Legal and accounting fees, printing costs and other expenses associated with the issuance of the Company's debt have been capitalized and are being amortized over the remaining term of the debt.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
GAS GATHERING AND TRANSPORTATION FACILITIES Depreciation of gas gathering and transportation facilities is provided using the straight-line method over estimated useful lives of 20 years.
OFFICE AND TRANSPORTATION EQUIPMENT Depreciation of office and transportation equipment is provided using the straight- line method over estimated useful lives which range from three to ten years.
GAS IMBALANCES Gas imbalances are accounted for under the sales method whereby revenues are recognized based on actual production sold. At December 31, 1996, the Company's gas balancing position was approximately 615,000 Mcf overproduced.
USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET EFFECTIVE Effective January 1, 1997, the Company will adopt the provisions of Statement of Position ("SOP") No. 96-1. Environmental Remediation Liabilities. This Statement provides authoritative guidance for recognition, measurement, display and disclosure of environmental remediation liabilities in financial statements. The Company has recorded environmental remediation liabilities of $1 million at December 31, 1996. SOP 96-1 is not expected to have a material impact on the Company's financial position or results of operations upon adoption.
NOTE 3 - BASIN ACQUISITIONS AND TIDE WEST MERGER
In March and June 1996, the Company acquired all of the Denver-Julesburg ("D-J") Basin oil and gas properties of Basin Exploration, Inc. ("Basin") (the "Acquisitions") for aggregate cash consideration of $125.5 million. The Acquisitions included a total of 850 gross wells with approximately 35 MMBoe of net proved reserves at December 31, 1995 and approximately 5,500 Boe of net daily production. Subsequent to the March acquisition, the Company sold $23.5 million of such assets to a limited liability company (the "Third Party") under an arrangement whereby the Third Party assumed all of the Company's liability for (and the Company was fully released from) $23.5 million of the Company's debt. On November 1, 1996, the Company exercised its option to repurchase the properties and assumed the debt of the Third Party. The assumed debt has been reflected as long-term bank debt in the December 31, 1996 financial statements. These Acquisitions were accounted for using the purchase method of accounting and the Company began consolidating the results of operations as of March and June, 1996.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
On June 17, 1996, the Company completed the merger of Tide West Oil Company ("Tide West") into a wholly owned subsidiary of the Company (the "Merger"). Pursuant to the Merger, Tide West shareholders received 0.6295 shares (totaling 6,169,181 shares in aggregate) of the Company's common stock and $8.704 cash for each outstanding share of Tide West common stock for an aggregate consideration of $187.7 million. The Merger added 1,259 gross wells, approximately 39.1 MMBoe of net proved reserves (at December 31, 1995) and 9,985 Boe of net daily production to the Company. Tide West was an independent oil and gas company with principal operations in portions of the Anadarko and Arkoma geologic basins located within Oklahoma and Texas, as well as additional operations located in Southern Oklahoma, Texas and New Mexico. The Company accounted for the Merger using the purchase method of accounting and began consolidating Tide West's results as of June 17, 1996.
NOTE 4 - PRO FORMA STATEMENTS
The following table sets forth the condensed unaudited pro forma operating results of the Company for the twelve months ended December 31, 1996 and 1995. The condensed pro forma operating results assume that both the Acquisitions and the Merger (as discussed in Note 3) had occurred on January 1, 1995. The condensed pro forma results are not necessarily indicative of the results of operations had the Acquisitions and the Merger been consummated on January 1, 1995, and may not necessarily be indicative of future performance.
NOTE 5 - RISK MANAGEMENT
The Company uses financial instruments to reduce its exposure to market fluctuations in the price and transportation cost of oil and natural gas. The Company's general strategy is to hedge price and location risk with swap, collar, floor and ceiling arrangements. When utilizing such instruments, the Company strives to hedge its production back to the wellhead, to minimize basis risk. In addition to hedging activities, the Company is engaged in using the financial markets to capture trading margins. The Company has established policies with respect to open positions which limit its exposure to market risk and requires reporting to management of the potential financial exposure on a daily basis resulting from both hedging and trading activities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
Hedging Activities Activities for hedging purposes are entered into by the Company to manage its exposure to price and location risks in the marketing of its oil and natural gas production and, in the case of its marketing activities, third party natural gas.
The Company has entered into the following forward sales and swap arrangements with respect to its natural gas production for the quarters indicated below (total average daily natural gas production for the quarter ended December 31, 1996 was 118,930 Mcf/day):
The Company has hedged through collar arrangements approximately two-thirds of its oil production at a floor price of $20.00 and a ceiling price of $24.00 per Bbl through the first quarter of 1997. Additionally, with respect to the hedging of third party natural gas, the Company has hedged 8.6 Bcf through December 1997 with offsetting physical positions at settlement prices which are based upon NYMEX future prices or other published indices.
Trading Activities The Company engages in the trading of various energy related financial instruments which require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, swap or other contractual arrangement. Company policy requires that financial instrument purchase and sales contracts be balanced in terms of contract volumes and the timing of performance and delivery obligations. As of December 31, 1996, all open positions were balanced with an offsetting position.
The Company accounts for these activities using the mark-to-market method of accounting. During 1996, gains of $462,000 were recognized in connection with these activities and are included in "trading and transportation revenues."
Credit Risk While notional amounts are used to express the volume of various derivative financial instruments, the amounts potentially subject to credit risk, in the event of nonperformance by the third parties, are substantially smaller. Counterparties to the swap, collar, floor and ceiling arrangements discussed above are investment grade financial institutions. Accordingly, the Company does not anticipate any material impact to its financial position or results of operations as a result of nonperformance by the third parties on financial instruments related to hedging activities or trading activities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
NOTE 6 - LONG-TERM DEBT
Debt at December 31, 1996 and 1995 consists of the following:
BANK DEBT On June 7, 1996, the Company entered into a $180 million revolving and senior term credit facility with The Chase Manhattan Bank, N.A., as Agent. On June 14, 1996, the Company amended the terms of its senior credit facility to increase the maximum credit amount to $350 million. Under the terms of the credit facility, no principal payments are required until June 14, 2001, assuming the Company maintains a borrowing base sufficient to support the outstanding loan balance. The borrowing base is based on the underlying value of the Company's oil and gas properties. This facility bears interest at a base rate plus 0% to 0.5% or LIBOR plus 0.75% to 1.5%. As part of the amendment to the credit facility, Tide West's senior bank debt in the amount of $39.5 million was fully repaid. Upon consummation of the $150 million senior subordinated notes offering (discussed below) and the application of the net proceeds therefrom, the borrowing base was amended to $275 million.
During the second quarter of 1995, the Company entered into an interest rate exchange agreement with a financial institution to hedge its interest rate on $40 million of the Company's borrowings at 7.76% through May 2002. Under the terms of the agreement, the difference between the Company's fixed rate of 7.76% and the three-month LIBOR rate plus 1.125% is received or paid by the Company. The Company, through the Merger with Tide West, was assigned interest rate exchange agreements with two financial institutions to hedge its interest rate on a total of $40 million of the Company's borrowings at rates ranging from 6.16% to 7.32% for 1997 through 1999. Under the terms of the agreement, the difference between the Company's fixed rate and the three-month LIBOR rate is received or paid by the Company.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
SENIOR SUBORDINATED NOTES In November 1993, the Company issued $75 million of its 9 7/8% senior subordinated notes due in 2003. The notes were priced to yield 10% and the Company received net proceeds of $71.9 million after underwriting commissions and offering costs. The proceeds of the notes were used to repay all outstanding indebtedness under the Company's bank credit facility and for working capital purposes. The notes pay interest semi-annually on June 1 and December 1. Under the terms of the notes, there are no sinking fund requirements and the Company is limited as to certain additional indebtedness beyond its existing credit facility if certain financial covenants are not maintained.
In November 1996, the Company issued $150 million of its 9 1/4% senior subordinated notes due in 2006. The notes pay interest semi-annually on May 15 and November 15. The notes were priced to yield 9.33% and the Company received net proceeds of $144.9 million after underwriting commissions and offering costs. The proceeds of the notes were used to replace a portion of the outstanding indebtedness under the Company's bank debt with fixed rate term debt.
OTHER DEBT In December 1995, the Company signed a $12.4 million non-interest bearing short-term note for the purchase of certain oil and gas properties. This note was repaid subsequent to year-end with proceeds from an additional draw on the Company's bank debt.
CARRYING VALUE At December 31, 1996 and 1995, the carrying amount of the Company's 9 7/8% senior subordinated notes was $74.6 million and $74.5 million and the estimated fair value was $78.3 million and $73.5 million, respectively. At December 31, 1996 the carrying amount of the 9 1/4% senior subordinated notes of $149.2 million approximated the fair value. The fair value is estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturity.
Based on borrowing rates available for bank loans with similar collateral, the fair values of the borrowings under the bank debt and other debt at December 31, 1996, are estimated to be their carrying value of $174 million and $.8 million, respectively.
NOTE 7 - STOCKHOLDERS' EQUITY
SERIES A CONVERTIBLE PARTICIPATING PREFERRED STOCK The Company has authorized 15,000,000 shares of $.001 par value Series A convertible preferred stock, of which no shares are currently issued or outstanding. The stock has a stated value of $13.50 and a liquidation preference of $1.00 per share.
SERIES A JUNIOR PREFERRED STOCK In February 1996, the Company authorized 300,000 shares of Series A junior preferred stock. The stock shall be issuable upon exercise of rights (the "Rights") issued pursuant to the agreement dated as of February 28, 1996 between the Company and Harris Trust Company of California, as Rights Agent (the "Rights Agreement"). The Rights Agreement was designed to protect the Company's shareholders in the event of takeover action that would deny them the full value of their investment (the "Rights Plan").
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
Terms of the Rights Plan provide for a dividend distribution of one right for each share of HS Resources, Inc. common stock to holders of record at the close of business on March 14, 1996. The Rights will automatically become part of and traded with existing and future shares of the Company's common stock. The Rights will become exercisable only in the event, with certain exceptions, an acquiring party accumulates 15% or more of HS Resources, Inc.'s voting stock, or if a party announces an offer to acquire 30% or more of HS Resources' voting stock. No separate rights certificates will be issued until after these thresholds are met. The Rights will expire on March 14, 2006.
Under the Rights Plan, if any person or group becomes the beneficial owner of 15 percent or more of the Company's common stock, or in the event of a merger or other business combination, each right will entitle the holder other than the acquiring party to purchase either HS Resources stock or shares in an "acquiring entity" at a 50 percent discount of the then current market value. HS Resources will be entitled to redeem the rights at $0.01 per right at any time prior to such time that a person or group acquires a 15 percent position in the Company's voting stock.
WARRANTS The Company had 746,262 warrants outstanding and exercisable at $8.98 per share as of December 31, 1996, 1995 and 1994.
RESTRICTED STOCK In connection with the issuance of 10,000 shares of restricted stock on December 2, 1996, the Company recorded $171,300 of deferred compensation for the difference between the deemed fair value for accounting purposes and the stock price as determined by the Company at the date of grant. This amount is presented as a reduction of stockholders' equity and will be amortized over the three year vesting period of the related stock.
NOTE 8 - PROVISION FOR INCOME TAXES
The provision for income taxes consists of the following:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
The deferred income tax expense during the years ended December 31, 1996, 1995 and 1994 results from the following:
The components of the net deferred tax liability as of December 31, 1996 and 1995 are as follows:
The Company recorded $58,117,144 of deferred tax liabilities and $2,027,400 of deferred tax assets in connection with its acquisition of Tide West.
The effective tax rate during 1996, 1995 and 1994 differs from the statutory rate of 34% principally because of the effects of state income taxes, net of federal tax benefit.
The Company has net tax operating loss carryforwards aggregating approximately $23 million available at December 31, 1996, to offset future taxable income. These carryforwards, if not previously utilized, expire in 2004 through 2010. Included in these carryforwards are approximately $3.4 million of losses acquired in the purchase of Tide West. The Company's ability to utilize these losses is subject to the "ownership change" limitation. The ownership change rules will limit the amount of Tide West's losses that can be used to approximately $.8 million annually.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
The Company has an alternative minimum tax (AMT) credit carryforward of approximately $982,000. AMT credits can be carried forward indefinitely and may only be used to reduce regular tax liabilities in future years when regular tax payable exceeds AMT payable. The Company also has a percentage depletion carryforward of approximately $6 million which can be used to reduce taxable income in the future and is not subject to expiration. Finally, the Company has investment tax credit carryforwards of approximately $169,000 which expire from 1997 through 1999. Due to the uncertainty that the investment tax credits will be applied against future tax liabilities, the Company has not given effect for the benefit of these amounts in calculating its deferred tax liability.
NOTE 9 - EMPLOYEE BENEFIT PLANS
401(K) AND PROFIT SHARING PLANS Effective June 30, 1989, the Company adopted two qualified defined contribution plans, the HS Resources, Inc. Employee Investment 401(k) Plan (the "401(k) Plan") and the HS Resources, Inc. Profit Sharing Plan (the "Profit Sharing Plan"). Employees are eligible to participate in both plans after one year of service. Under the 401(k) Plan, participants may make regular pretax contributions of up to 10% of their compensation (up to a maximum of $9,500) and receive matching contributions from the Company in an amount determined by the Board of Directors. All contributions to the 401(k) Plan are vested 100% upon participation. Under the Profit Sharing Plan only the Company can make contributions. Company contributions are determined by the Board of Directors and are vested to participants over five years of service. Company contributions to both plans are included in general and administrative expenses in the accompanying statements of operations.
At December 31, 1996, the Company accrued approximately $450,000 for the 1996 contribution to the 401(k) Plan. Contributions to the plans were $211,596 and $378,141 in 1995 and 1994, respectively.
STOCK OPTION PLAN The Company has an Employee Stock Incentive Plan (the "Plan") whereby directors, officers, key employees, and consultants of the Company are entitled to receive incentive stock options, non-qualified stock options, and stock appreciation rights. One million five hundred thousand shares of the Company's common stock are subject to the Plan. Additionally, the Company may grant restricted stock pursuant to the Plan. Options granted pursuant to the Plan shall be exercisable for no more than ten years at no less than fair market value (85% of fair market value in the case of non-qualified stock options) on the date of the grant. The Plan expires in April 1997. The Company currently intends to present a new equity incentive plan for approval by the shareholders at this years annual shareholders meeting. The Company accounts for this plan under Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, under which no compensation cost was recognized during 1996 and 1995. During 1996, 1995 and 1994, the Company implemented SFAS No. 123, Accounting for Stock Based Compensation. The implementation of SFAS 123 did not result in a material impact on the Company's net income and earnings per share.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
The following table summarizes activity with respect to outstanding stock options for the years 1996, 1995 and 1994:
Of the 773,520 options outstanding at December 31, 1996, 470,770 options are fully vested and have exercise prices between $6.67 and $12.00, with a weighted average exercise price of $7.26 and a weighted average remaining contractual life of 2.7 years. The remaining 302,750 options have exercise prices between $10.13 and $25, with a weighted average exercise price of $15.87 and a weighted average remaining contractual life of 6.43 years. Of these options 155,900 are exercisable; their weighted average exercise price is $17.00.
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 1996 and 1995, respectively: risk free interest rate of 5.8%; expected dividend yield of 0%; expected life of 6 years; expected volatility of 67%.
NOTE 10 - COMMITMENTS AND CONTINGENCIES
ENVIRONMENTAL MATTERS In May 1995, the Company was named by the EPA pursuant to a RCRA administrative order as one of two respondents in addition to the owner/operator of an oilfield production water evaporation facility. The order requires that work be performed to abate a perceived endangerment to wildlife, the environment or public welfare. The Company and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
other non-operator respondents are working together with the EPA to develop characterization studies of the site, and have caused the facility to be permanently closed. Based on the Company's current knowledge and its expectation of proportionate reimbursement from other parties who utilized the facility, the Company does not believe that its share of the reclamation costs will have a material impact on its financial condition or results of operations. By agreement with other contributing parties, the Company is currently paying approximately 50% of the costs associated with the project, but after recovery from additional liable parties, the Company's percentage share of overall costs may be reduced to as low as 40%. The Company has spent approximately $460,000 on its behalf to date on the project. The Company's share of total costs associated with the project, at the 50% level of participation, are currently estimated to range from $1 to $2 million over three years. The full amount of the Company's estimated liability is reflected in the December 31, 1996 financial statements. See Note 2 of Notes to Consolidated Financial Statements.
The Company is subject to minor lawsuits incidental to operations in the oil and gas industry. The Company believes it has meritorious defenses to all lawsuits in which it is a defendant and will vigorously defend against them. The resolution of such lawsuits, regardless of the outcome, will not have a material adverse effect on the Company's financial position or results of operations.
OPERATING LEASES The Company is obligated under noncancelable operating leases for office space and certain equipment. Total rental expense related to these leases was $1,653,378, $1,263,930 and $992,509 for December 31, 1996, 1995 and 1994, respectively. Future minimum lease payments as of December 31, 1996 are:
NOTE 11 - UNEARNED INCOME
During the twelve months ended December 31, 1995 and 1994 the Company received $575,000, and $2,300,000, respectively from an unaffiliated third party as payment for tax credits associated with gas production from certain of the Company's oil and gas properties. The unaffiliated third party was entitled to these tax credits as gas production occurred. The Company recorded the proceeds as unearned income and amortized the amount to the gas revenues as the gas was produced and the credits were generated. The agreement was terminated as of December 1, 1995. The Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
recognized approximately $1,600,000 and $1,300,000, of other gas revenues during the years ended December 31, 1995 and 1994, respectively, related to the amortization of this unearned income.
NOTE 12 - OTHER GAS REVENUES
The Company and its subsidiaries continue to enter into transactions designed to monetize the Company's Section 29 tax credits. In nine separate transactions, starting on December 1, 1995, the Company has sold to unaffiliated third parties its right, title and interest in certain of its oil and gas leases and mineral interests. The sale will enable the third parties to earn tax credits associated with future oil and gas production. The Company reserved a volumetric production payment that entitles it to 100% of the net cash flows from the properties. The Company will receive periodic payments from the third parties based on tax credits generated from the gas production on the sold properties. The Company recognized approximately $2.7 million and $177,000 of other gas revenues associated with the tax credits during the years ended December 31, 1996 and 1995, respectively.
NOTE 13 - OIL AND GAS ACTIVITIES
MAJOR PURCHASERS In 1996, sales to Amoco Production Company and Panenergy accounted for approximately $29,300,000 and $22,800,000 or 27.3% and 21.2%, of total oil and gas sales, respectively. In 1995, sales to Amoco Production Company and K N Marketing, Inc. accounted for approximately $24,600,000 and $6,120,000 or 46% and 11.5%, of total oil and gas sales, respectively. In 1994, sales to Amoco Production Company accounted for approximately $46,548,000 or 79%, of total oil and gas sales.
COSTS INCURRED Costs incurred in oil and gas operations and the related depreciation, depletion, and amortization per equivalent unit-of-production are as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
NOTE 14 - SUMMARY OF GUARANTEES ON 9 1/4% SENIOR SUBORDINATED NOTES
In November 1996, the Company issued $150 million of its 9 1/4% senior subordinated notes due in 2006. The Notes are general, unsecured obligations of the Company, subordinated in right of payment to all existing and any future senior indebtedness of the Company. The Notes rank pari passu with existing and any future senior subordinated indebtedness and senior to any future subordinated indebtedness of the Company. The Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured, senior subordinated basis by two of the Company's subsidiaries, Orion Acquisition, Inc. and HSRTW, Inc (the "Subsidiary Guarantors").
Sections 13 and 15(d) of the Securities Exchange Act of 1934 require presentation of the following supplemental condensed consolidating financial statements of the Subsidiary Guarantors. Separate complete financial statements of the respective Subsidiary Guarantors are not material to investors. There are no significant contractual restrictions on distributions from each of the Subsidiary Guarantors to the Company.
Investments in subsidiaries are accounted for by the parent under the equity method for purposes of the supplemental condensed consolidated financial statement presentation. Under this method, investments are recorded at cost and adjusted for the parent company's ownership share of the subsidiaries' cumulative results of operations. In addition, investments increase in the amount of contributions to subsidiaries and decrease in the amount of distributions from subsidiaries. The elimination entries eliminate the equity method investment in subsidiaries and equity in earnings of subsidiaries, intercompany payables and receivables and other transactions between subsidiaries including contributions and distributions.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
CONDENSED CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 1996
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS TWELVE MONTHS ENDED DECEMBER 31, 1996
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS TWELVE MONTHS ENDED DECEMBER 31, 1996
Certain non cash transactions have taken place between HSR and its subsidiaries related to the equity contributions. Accordingly, these transactions are not reflected in the statements of cash flows.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
NOTE 15 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
OIL AND GAS NET RESERVES The following unaudited tables set forth the estimated quantities of proved oil and gas reserves for the Company and the changes in total proved reserves as of December 31, 1996, 1995 and 1994. All such reserves are located in the United States. The amounts as of December 31, 1996, 1995 and 1994, were prepared by the Company and substantially all were reviewed by either Williamson Petroleum Consultants, Inc. or by Netherland, Sewell & Associates, Inc., each an independent petroleum engineering consulting firm.
ANALYSIS OF CHANGES IN PROVED RESERVES
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. However, for ceiling test purposes, future income taxes are estimated using the "short-cut" method.
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) HS Resources, Inc.
Estimated future cash inflows are computed by applying year-end prices of oil and gas to year-end quantities of proved reserves. Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves held by the Company as of the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Estimated future income tax expenses are calculated by applying year-end statutory tax rates (adjusted for permanent differences) to estimated future pretax net cash flows related to proved oil and gas reserves, less the tax basis of the properties involved. No deductions were made for general overhead, depreciation and other indirect costs. The average year-end prices used in the projections were $24.92/Bbl of oil and $3.39/Mcf of gas at December 31, 1996, $18.59/Bbl of oil and $1.65/Mcf of gas at December 31, 1995 and $15.65/Bbl of oil and $1.77/Mcf of gas at December 31, 1994.
These estimates were determined in accordance with SFAS No. 69. Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas price changes, and the fact that the basis for such estimates vary significantly, management believes the usefulness of these projections of cash flow is limited. Estimates of future net cash flows do not represent management's assessment of future profitability or future cash flow to the Company. Management's investment and operating decisions may be based upon reserve estimates that include price, cost and production assumptions which are different from those used here.
Applying current costs and prices and a 10% standard discount rate allows for comparability but does not convey absolute value. The discounted amounts arrived at are only one measure of financial quantification of proved reserves. Reservoir engineering is a process of making educated estimates of underground accumulations of oil and gas and the amounts and timing of recovery thereof, which cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, reserve estimates are often materially different from the quantities of oil and gas which are ultimately recovered. Future development of the properties in which the Company has an interest, including additional drilling activities, production results from wells not yet producing, and additional production results from currently producing wells, may provide information which justify revisions, either upward or downward, of reserve estimates. Such adjustments may be material.
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, 1996 and 1995, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of HS Resources, Inc. and subsidiaries as of December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
/s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP
Denver, Colorado
February 24, 1997
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 Amended Note and Warrant Purchase Agreement dated January 15, 1991, among NGP, Resolute Resources, Inc., and the Company. (Incorporated by reference to Exhibit 4.4.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 1990, filed February 14, 1991.)
10.1.1 Amendment No. 1 to Note and Warrant Purchase Agreement dated June 28, 1991, between the Company and NGP. (Incorporated by reference to Exhibit 4.4.2 to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 1991, filed September 30, 1991.)
10.1.2 Second Amendment to Note and Warrant Purchase Agreement dated August 17, 1992, between the Company and NGP. (Incorporated by reference to Exhibit 4.2.2 to Amendment No. 2 to the Company's Registration Statement on Form S-1, No. 33-52774, filed November 19, 1992.)
10.1.3 Third Amendment to Note and Warrant Purchase Agreement dated October 21, 1993, between the Company and NGP. (Incorporated by reference to Exhibit 4.1.3 to Amendment No. 2 to the Company's Registration Statement on Form S-3, No. 33-70354, filed November 23, 1993.)
10.2 Amended and Restated Warrant Agreement dated January 15, 1991, between NGP and the Company. (Incorporated by reference to Exhibit 4.5.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 1990, filed February 14, 1991.)
10.3 Amended Warrant No. W-1, dated January 15, 1991, and issued by the Company to NGP. (Incorporated by reference to Exhibit 4.6.1 to the Form 8, Second Amendment to Form 10, filed April 8, 1991.)
10.3.1 Amendment No. 1 to Amended Warrant No. W-1, dated December 30, 1991, and issued by the Company to NGP. (Incorporated by reference to Exhibit 4.6.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 1991, filed on February 14, 1991.)
10.4 Form of Warrant No. W-10, dated January 28, 1992, and issued by the Company to NGP. (Incorporated by reference to Exhibit 4.16 to Amendment No. 1 to the Company's Registration Statement on Form S-1, No. 33-52774, filed November 9, 1992.)
10.5* 1987 Stock Incentive Plan, as amended December 2, 1996.
10.6 Common Stock Purchase Warrant dated July 12, 1990 by the Company to James E. Duffy. (Incorporated by reference to Exhibit 10.5 to the Form 8, Second Amendment to Form 10, filed April 8, 1991.)
10.7 HS Resources, Inc. Rule 701 Compensatory Benefit Plan. (Incorporated by reference to Exhibit 10.5.2 to the Form 8, Second Amendment to Form 10 filed April 8, 1991.)
10.8 1992 Directors' Stock Option Plan. (Incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Company's Registration Statement on Form S-1, No. 33-52774, filed November 9, 1992.)
10.8.1 1993 Directors' Stock Option Plan. (Incorporated by reference to Exhibit 10.8.1 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, filed March 31, 1994 (as amended by Form 10- K/A-1 on April 8, 1994.))
10.9 Form of Indemnification Agreement for Directors of the Company. (Incorporated by reference to Exhibit 10.16 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1995, filed March 25, 1996.)
10.10 Lease Agreement dated October 6, 1993, between the Company and JMB Group Trust IV and Endowment and Foundation Realty, Ltd. -- JMB III for the premises at One Maritime Plaza, San Francisco, California. (Incorporated by reference to Exhibit 10.13 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1993, filed March 31, 1994 (as amended by Form 10-K/A-1 on April 8, 1994.))
10.11 Lease Agreement dated March 28, 1994, between the Company and 1999 Broadway Partnership for the premises at 1999 Broadway, Denver, Colorado. (Incorporated by reference to Exhibit 10.15 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1994, filed August 12, 1994.)
10.12 Interest exchange agreement between The Chase Manhattan Bank, N.A. and the Company dated May 9, 1995. (Incorporated by reference to Exhibit 10.19 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, filed August 14, 1995.)
10.13 Amended and Restated Agreement and Plan of Merger, dated as of April 29, 1996, among the Company, HSR Acquisition, Inc. and Tide West Oil Co. (Incorporated by reference as Annex A to Amendment No. 2 to the Company's Registration Statement on Form S-4, No. 333-01991, filed on May 2, 1996.)
10.14 Agreement for Purchase and Sale of Assets, dated as of February 24, 1996, among the Company, Basin Exploration, Inc. ("Basin") and Orion Acquisition, Inc. ("Orion"). (Incorporated by reference to Exhibit 2.3 to the Company's Form 8-K, filed March 12, 1996.)
10.15 Agreement for Purchase and Sale of Assets [Wattenberg], dated as of February 24, 1996, among the Company, Orion and Basin. (Incorporated by reference to Exhibit A to the Company's Schedule 13D relating to Basin Exploration, Inc. filed on March 6, 1996.)
10.16 Purchase and Sale Agreement, dated December 1, 1995, between the Company and Wattenberg Gas Investments, LLC. (Incorporated by reference to Exhibit 10.26 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1995, filed March 25, 1996.)
10.17 Rights Agreement, dated as of February 28, 1996, between the Company and Harris Trust Company of California as Rights Agent. (Incorporated by reference to Exhibit 1 to the Company's Form 8-A, filed March 11, 1996.)
10.18 Purchase and Sale Agreement dated March 25, 1996 between Orion Acquisition, Inc., the Company and Wattenberg Resources Land, L.L.C. (Incorporated by reference to Exhibit 10.28 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1996, filed May 15, 1996.)
10.19 Credit Agreement, dated as of June 7, 1996, among the Company and The Chase Manhattan Bank, N.A. ("Chase"), as agent of the Banks signatory thereto. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.20 Amended and Restated Credit Agreement dated as of June 14, 1996, among the Company, Chase as agent, and the Banks signatory thereto. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.21 First Amendment to Amended and Restated Credit Agreement dated as of June 17, 1996, by and among the Company and Chase in its individual capacity and as agent for the Lenders. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996,filed August 14, 1996.)
10.22 Second Amendment to Amended and Restated Credit Agreement dated as of November 27, 1996 among the Company and Chase in its individual capacity and as agent for the Lenders. (Incorporated by reference to Exhibit 10.22 to the Company's Registration Statement on Form S-4, No 333-19433, filed January 8, 1997.)
10.23 Assignment of Liens and Amendment of Amended, Restated and Consolidated Mortgage, Assignment of Production, Security Agreement and Financing Statement, dated June 14, 1996, among Chase (Assignor), Chase (Assignee) and the Company. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.24 Guaranty Agreement by HSR Acquisition, Inc. in favor of Chase, as Agent, dated June 14, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.25 Guaranty Agreement by Orion Acquisition, Inc. in favor of Chase, as Agent, dated June 14, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.26 First Amendment to Guaranty Agreement dated as of June 17, 1996, by and among Orion Acquisition, Inc. and Chase, in its individual capacity and as agent for the Lenders. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.27 First Amendment to Guaranty Agreement dated as of June 17, 1996, by and among HSRTW, Inc. (formerly HSR Acquisition, Inc.) and Chase, in its individual capacity and as agent for the Lenders. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.28 Third Amendment and Supplement to Amended, Restated and Consolidated Mortgage, Assignment of Production, Security Agreement and Financing Statement, dated as of July 15, 1996, by and between the Company and Chase. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.29 Hedging Agreement between Chase and the Company dated May 1, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.30 Hedging Agreement between Chase and the Company dated May 1, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.31 Hedging Agreement between Chase and the Company dated June 1, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
11 Purchase and Sale Agreement between the Company and Wattenberg Gas Investments, LLC dated April 25, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
11 Purchase and Sale Agreement between Wattenberg Resources Land L.L.C. and Wattenberg Gas Investments, LLC dated May 21, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.33 Purchase and Sale Agreement between Wattenberg Resources Land L.L.C. and Wattenberg Gas Investments, LLC dated May 21, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.34 Purchase and Sale Agreement between Orion Acquisition, Inc. and Wattenberg Gas Investments, LLC dated June 14, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.35 Purchase and Sale Agreement between Wattenberg Resources Land L.L.C. and Wattenberg Gas Investments, LLC dated June 14, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.36 Purchase and Sale Agreement between Orion Acquisition, Inc. and Wattenberg Gas Investments, LLC dated June 14, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.37 Purchase and Sale Agreement between the Company and Wattenberg Gas Investments, LC dated June 28, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.38 Purchase and Sale Agreement between HSRTW, Inc. and Westtide Investments, LLC dated August 9, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, filed November 7, 1996.)
10.39 Acquisition Agreement between the Company and TCW Portfolio No. 1555 DR V Sub-Custody Partnership, L.P. dated August 30, 1996. (Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, filed November 7, 1996.)
10.40 Purchase Agreement dated November 27, 1996 among the Company, Orion Acquisition, Inc., HSRTW, Inc., Salomon Brothers Inc., Chase Securities Inc., Lehman Brothers Inc., and Prudential Securities Incorporated. (Incorporated by reference to Exhibit 10.40 to the Company's Registration Statement on Form S-4, No 333- 19433, filed January 8, 1997.)
10.41 Registration Agreement dated November 27, 1996 among the Company, Orion Acquisition,Inc., HSRTW, Inc. and Salomon Brothers Inc. in its individual capacity and as agent for Chase Securities Inc., Lehman Brothers Inc., and Prudential Securities Incorporated. (Incorporated by reference to Exhibit 10.41 to the Company's Registration Statement on Form S-4, No 333-19433, filed January 8, 1997.)
10.42* Employment Agreement between James Piccone and the Company dated April 21, 1995.
27* Finanacial Data Schedule
- ---------- * Filed herewith
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 17th day of March.
HS RESOURCES, INC.
By /s/ Nicholas J. Sutton ----------------------------------- Nicholas J. Sutton Chairman of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities indicated on this 17th day of March.
Signature Title --------- -----
/s/ Nicholas J. Sutton Chairman of the Board, Chief - ------------------------- Executive Officer Nicholas J. Sutton (Principal Executive Officer)
/s/ P. Michael Highum President and Director - ------------------------- P. Michael Highum
/s/ James E. Duffy Chief Financial Officer - ------------------------- and Director James E. Duffy (Principal Financial Officer)
/s/ Annette Montoya Vice President - Accounting - ------------------------- and Controller Annette Montoya (Principal Accounting Officer)
/s/ Kenneth A. Hersh Director - ------------------------- Kenneth A. Hersh
/s/ Michael J. Savage Director - ------------------------- Michael J. Savage
/s/ Philip B. Smith Director - ------------------------- Philip B. Smith
EXHIBIT INDEX