ITEM 1. BUSINESS
GENERAL
Union Pacific Resources Group Inc., a Utah corporation (the "Company"), is engaged primarily in the exploration for and the development and production of natural gas, natural gas liquids and crude oil in several major producing basins in the United States and Canada. The Company emphasizes natural gas in its exploration and production activities and also owns and operates significant assets, in proximity to its principal producing properties, dedicated to "gas value chain" activities, which consist of the gathering, processing, transportation and marketing of natural gas and natural gas liquids. The Company, through its wholly owned subsidiary, Union Pacific Fuels, Inc. ("UP Fuels"), markets approximately 72% of the Company's natural gas, 88% of its crude oil and 96% of its natural gas liquids, together with significant volumes of natural gas, natural gas liquids and crude oil produced by others. In addition, the Company engages in the hard minerals business through nonoperated joint venture and royalty interests in several coal and trona (natural soda ash) mines located on lands within and adjacent to its Land Grant (hereinafter defined) holdings in Wyoming. Over 90% of the Company's revenues, assets and reserves are generated or located in the United States. See "Business Segment Information" on page 37.
In October 1995, the Company sold 42.5 million shares of its common stock in an initial public offering (the "Offering"). The Company's stock is traded on the New York Stock Exchange under the symbol "UPR." Prior to completion of the Offering, the Company was wholly owned by Union Pacific Corporation, a Utah corporation ("UPC"). Upon completion of the Offering and until October 15, 1996, UPC owned approximately 83% of the Company's outstanding common stock. Concurrent with the Offering, UPC announced its intention to distribute its remaining ownership interest in the Company to its shareholders as a dividend by means of a tax-free distribution (the "Distribution"). On October 15, 1996, the Distribution was consummated.
UPC acquired Champlin Petroleum Company ("Champlin") in 1970 to manage the exploitation of its oil and gas operations on the Land Grant. The Land Grant consists of land granted by the Federal government to a predecessor of UPC in the mid-1800s which passes through the states of Colorado and Wyoming and into Utah and intersects several highly productive oil and gas basins. In the Land Grant Area, the Company has fee ownership of the mineral rights under approximately 7.9 million acres constituting the initial Land Grant and controls the mineral rights under approximately 700,000 additional acres. In 1971, UPC combined its own oil and gas operations with those of Champlin. In 1987, the Champlin name was changed to Union Pacific Resources Company ("UPRC") and UPRC also became responsible for managing UPC's hard mineral assets. In October 1995, UPRC and certain oil and gas operations of other affiliated companies which were wholly owned subsidiaries of UPC, representing, collectively, UPC's natural resources business segment, were combined to form the Company.
BUSINESS STRATEGY
In each of its core areas, the focus of the Company is on the exploration for and development of natural gas and crude oil resources and on efforts to increase margins through reductions in drilling and operating costs and effective and efficient sales and distribution networks. The Company's strategy is to apply economies of scale, its operating experience in its core geographic areas and its expertise in advanced drilling and completion technologies, to increase production by expanding the Company's North American drill site inventory and enhancing well performance results. In addition to developing its existing properties, the Company also increases drill site inventory through exploration, farm-in agreements and acquisitions of properties and companies. The Company's growth in recent years has occurred through exploration and development in core geographic areas as well as producing property purchases, the most significant of which was the $725 million acquisition of Amax Oil & Gas, Inc. ("Amax") in March 1994.
OIL AND GAS OPERATIONS
The Company's oil and gas activities are concentrated in six core geographic areas: (1) the Austin Chalk trend in Texas and Louisiana, (2) the Rockies, consisting of the western portion of the Land Grant Area in Wyoming and Utah, (3) Plains/Canada, consisting of the eastern portion of the Land Grant Area in Colorado and Wyoming, with additional operations primarily in Kansas and western Canada, (4) the onshore and offshore Gulf Coast area, (5) eastern and southern Texas and (6) western Texas. Natural gas and natural gas liquids constituted 86% of the Company's total proved reserves of over 3.5 Tcfe as of December 31, 1996, and 82% of the Company's sales volumes of 1.7 Bcfed for the year then ended. For the same period, approximately 64% of the Company's production from producing properties was attributable to Company-operated properties.
The following table sets forth certain reserve and sales information as of December 31, 1996 with respect to each of the Company's business units.
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(1) Reflects future production attributable to (i) the Company's natural gas, natural gas liquids and crude oil production from producing properties and (ii) the Company's portion, by virtue of its ownership interest in gas processing facilities, of natural gas and natural gas liquids earned by such facilities through the processing of the Company's production from producing properties. At some of its gas processing facilities, the Company earns gas and natural gas liquids through the processing of third party volumes. Volumes attributable to third party processing are not reflected in the Company's proved reserves.
(2) Excludes natural gas, natural gas liquids and crude oil purchased from third parties for resale by UP Fuels. See "Business -- Marketing."
Austin Chalk Business Unit. The Austin Chalk business unit manages the Company's oil and gas activities in the Austin Chalk trend, which extends 700 miles from southern Texas through central and eastern Texas into Louisiana. At present, the Company's Austin Chalk production is located primarily in the Giddings and Brookeland fields. The Louisiana Extension of the Austin Chalk currently is the focus of significant activity. Since 1988, the Company has participated in the drilling of approximately 1,300 horizontal wells and has made aggregate capital expenditures of $1.9 billion in the Austin Chalk area. The Company currently controls approximately two million developed and undeveloped net acres in the Austin Chalk and has increased its sales volumes from 37 MMcfed in January 1990 to an average of 559 MMcfed during 1996. During 1996, 90% of the Company's production from the Austin Chalk was attributable to Company-operated properties.
Rockies Business Unit. The Rockies business unit manages the Company's oil and gas activities in the western portion of the Land Grant Area in Wyoming and Utah. The Company's operations in the Rockies are concentrated in the Green River Basin and the Overthrust area. The Company currently controls approximately 3.5 million developed and undeveloped net acres in the Rockies, principally attributable to its Land
Grant ownership. During 1996, 23% of the Company's production from the Rockies was attributable to Company-operated properties.
Plains/Canada Business Unit. The Plains/Canada business unit manages the Company's oil and gas activities primarily in three areas: the eastern portion of the Land Grant Area in Colorado and Wyoming, the Hugoton/Panoma field in Kansas and fields in western Canada. The Company currently controls more than 5.7 million developed and undeveloped net acres in Plains/Canada, principally attributable to its Land Grant ownership. As of December 31, 1996, the Company had an interest in approximately 1,300 gross producing wells in the Plains/Canada area. The Company also had royalty interests in 3,700 producing wells in Plains/Canada in which the Company did not also own a working interest. During 1996, 49% of the Company's production from Plains/Canada was attributable to Company-operated properties.
Gulf Onshore/Offshore Business Unit. The Gulf Onshore/Offshore business unit manages the Company's oil and gas activities in the Gulf of Mexico and the onshore Gulf Coast. In addition to its producing operations, the unit conducts exploration activities in southern Louisiana, southern Texas and the Gulf of Mexico. During 1996, 49% of the Company's production from the Gulf Onshore/Offshore area was attributable to Company-operated properties.
East/South Texas Business Unit. The East/South Texas business unit manages the Company's oil and gas activities in two major producing areas: the Carthage and Oakhill fields in northeastern Texas and the Stratton/Agua Dulce area in southern Texas. The Company also controls significant gathering, processing and transportation assets in East/South Texas that are integral to its natural gas production activities. For the year ended December 31, 1996, 87% of the Company's production from East/South Texas was attributable to Company-operated properties.
West Texas Business Unit. The West Texas business unit manages the Company's oil and gas activities in western Texas, principally in the Ozona field in the Permian Basin area. The Company obtained its producing properties in the Ozona field through the acquisition of Amax in March 1994. The Amax acquisition included approximately 850 operated natural gas wells in the Ozona field, which is characterized by long-lived natural gas wells that typically produce for 30 or more years. Since the Amax acquisition, the Company has drilled over 600 wells in the Ozona area and has substantially modernized and expanded its gathering, processing and transportation facilities. As of December 31, 1996, approximately 84% of the gross producing wells in the West Texas area were Company operated. During 1996, 93% of the Company's production from West Texas was attributable to Company-operated properties.
Plants and Pipelines. The Company owns interests in 21 natural gas processing plants, 16 of which it operates, with a current throughput capacity of 3.2 Bcfd (1.6 Bcfd net to the Company). Aggregate throughput of the Company's gas processing plants for the year ended December 31, 1996 averaged 84% of the plants' aggregate design capacity. For the year ended December 31, 1996, production of natural gas liquids attributable to the Company's ownership interest in gas processing facilities averaged approximately 39.8 MBbld. In addition to the gas value chain assets included in the Amax acquisition, the Company has invested approximately $100 million per year in each of the last three years to increase processing and gathering capacity. The Company currently is developing a gas processing facility in the Austin Chalk and has plans to expand its Patrick Draw plant in the Rockies as well as its East Texas plant complex. See "Properties -- Gas Processing Assets."
During 1996, the Company became a partner with Arco Pipeline Company on a 50/50 basis in the Black Lake liquids pipeline, a 270-mile pipeline in Louisiana which can transport up to 45 MBbld of natural gas liquids from the Austin Chalk area to markets on the Gulf Coast. Both the Black Lake and Panola pipelines deliver unfractionated natural gas liquids to the Enterprise and Mont Belvieu I fractionators in which the Company has equity ownership. The Company also has a 55% nonoperating interest in the Ferguson-Burleson County Gas Gathering System, a 585 MMcfd capacity system serving the deep Giddings area of the Austin Chalk and controls both the 265-mile Overland Trail Transmission Company pipeline serving the Green River Basin in the Rockies and the 100 MMcfd Wahsatch Gathering System, a sour gas pipeline serving the Yellow Creek and Cave Creek areas of the Overthrust. In general, the Company owns extensive gathering systems
behind each of its natural gas processing plants which it uses to transport unprocessed gas from producing wells to the inlet of the plant.
Marketing. In 1996, the Company, primarily through UP Fuels, sold approximately 1.8 Bcfd of natural gas (about 56% of which represented the Company's equity production), 151.6 MBbld of natural gas liquids (including 83.3 MBbld of third party liquids) and 63.5 MBbld of crude oil and condensate (including 12.9 MBbld of third party crude oil and condensate).
In addition, UP Fuels provides storage and transportation services in certain natural gas supply and market areas and manages the Company's market hubs in East Texas and the Land Grant Area. The Company has a diverse customer base for natural gas, which includes local distribution companies, power generation facilities, pipelines, industrial plants and other wholesale marketing companies. The natural gas liquids customers that UP Fuels targets are wholesalers, industrial end users and traders. UP Fuels prefers to sell its natural gas liquids in local markets, which generally offer more attractive pricing. Natural gas liquids not sold locally are shipped from the various plants by pipelines to the Company's partially owned fractionators in Mt. Belvieu, Texas. Where possible, UP Fuels sells crude oil directly to refiners. If these customers are not available locally, UP Fuels exchanges or sells the crude oil volumes to major trading locations where they are sold to both refiners and marketers.
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the Company's volumes of and average price realizations for natural gas, natural gas liquids and crude oil sales, and average production costs per Mcfe for each of the last three years.
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(1) Does not include the Company's portion, by virtue of its ownership in gas processing facilities, of natural gas and natural gas liquids earned by such facilities in connection with the processing of natural gas.
(2) Includes lease operating costs, production overhead, other operating expenses and taxes other than income taxes.
(3) Represents the Company's portion, by virtue of its ownership interest in gas processing facilities, of natural gas and natural gas liquids earned by such facilities in connection with the processing of natural gas. The portion of the total average daily sales volumes representing the Company's portion earned by such facilities with respect to processing the Company's production for each of the three years ended December 31, 1994, 1995 and 1996 are 43.9 MMcfed, 66.5 MMcfed and 77.1 MMcfed, respectively. See "Supplementary Information -- Average Daily Production and Sales Volume" on page 58.
MINERALS
The Minerals business unit contributes significantly to the Company's operating income by exploiting the hard minerals portion of the Company's extensive fee mineral interests in the Land Grant through nonoperated joint venture and royalty arrangements in coal and trona (natural soda ash) mines. In general, the Company reinvests the cash flow from its hard minerals operations in its oil and gas business units. The Minerals business unit generated $120 million of operating income during 1996, as follows:
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(1) Includes properties leased to five soda ash producers, estimated to contain resources sufficient to support over 30 years of production at current production levels.
(2) The Company leases coal resources to six operating mines. In 1996, 62% of the Company's coal royalties were attributable to a single mine which supplies an adjacent power station that is owned and operated by affiliates of the mine owners.
(3) Represents a 49% interest in OCI Wyoming LP, a nonoperated joint venture.
(4) Represents the Company's 50% nonoperating interest in Black Butte Coal Company. Of this amount, $54.8 million is attributable to a single coal supply contract, the financially beneficial terms of which terminate at the end of 2001. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 12 to the Consolidated Financial Statements.
The Company's low sulfur coal deposits compete with other western coals for industrial and utility boiler markets. At current coal pricing and extraction cost levels, however, most of this resource is not economic to extract, except for sale to local markets. As a result, there are limited opportunities for new coal mine development in the Land Grant.
The world's largest deposit of trona ore, constituting 90% of the world's known trona resources, is located in the Green River Basin in southwestern Wyoming. Approximately 40% of this trona deposit lies within the
Land Grant and is therefore owned by the Company. Natural soda ash, which is produced by refining trona ore, is used primarily in the production of glass for containers and flat glass, in the paper and water treatment industries and in the manufacture of certain chemicals and detergents. Natural soda ash from Wyoming has grown to 30% of the world soda ash supply with the remainder principally from synthetic processes, and will continue to expand while worldwide demand continues to increase. As a result of the continued increase in the worldwide demand for soda ash, the Company, along with its partner Oriental Chemical Industries, Inc., plans to expand the OCI Wyoming LP soda ash facility by 950,000 tons per year, from the plant's current nameplate capacity of 2.3 million tons per year, by 1999. The Company's share of expansion costs is expected to be funded primarily with partnership debt.
COMPETITION
The oil and gas industry is highly competitive. The Company actively competes for reserve acquisitions and for exploration leases, licenses and concessions and skilled industry personnel, frequently against companies with substantially larger financial and other resources. The Company's competitors include major integrated oil and gas companies and numerous other independent oil and gas companies and individual producers and operators. To the extent the Company's capital budget is lower than that of certain of its competitors, the Company may be disadvantaged in effectively competing for certain reserves, leases, licenses and concessions. Competitive factors include price, contract terms, and types and quality of service, including pipeline distribution logistics and efficiencies.
GOVERNMENT REGULATION
The Company's natural gas, natural gas liquids and crude oil exploration, development and production operations are subject to extensive rules and regulations promulgated by Federal, provincial, state and local authorities.
Numerous Federal, state and local departments and agencies have issued rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for noncompliance. State statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. Most states in which the Company operates also have statutes and regulations governing conservation and safety matters, including the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing of such wells. Such statutes and regulations may limit the rate at which oil and gas otherwise could be produced from the Company's properties. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability.
A substantial portion of the Company's oil and gas leases in the Gulf of Mexico and a portion of its onshore leases were granted by the United States Government and are administered by two agencies within the Department of the Interior: the Bureau of Land Management ("BLM") and the Minerals Management Service ("MMS"). Such leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed BLM and MMS regulations and orders. Certain operations on such leases must be conducted pursuant to appropriate permits issued by the BLM and the MMS in addition to permits required from other agencies (such as the Coast Guard, Army Corps of Engineers and Environmental Protection Agency). The MMS also administers bonding requirements and has the right to require lessees to post supplemental bonds if it deems that additional security is necessary to cover royalties due or the costs of regulatory compliance.
Under certain extraordinary circumstances, the Federal agencies have the power to suspend or terminate Company operations on Federal leases. Any such suspension or termination could materially and adversely affect the Company's financial condition and operations. The MMS also intends to adopt financial responsibility regulations under the Oil Pollution Act of 1990. See "Environmental Regulation -- Oil Spills."
Currently there are no laws that regulate the price for sales of natural gas, natural gas liquids and crude oil by the Company. However, the Company's rates charged and terms and conditions for the movement of gas in interstate commerce through certain of its intrastate pipelines and production area hubs are subject to
regulation under the Natural Gas Policy Act of 1978 ("NGPA"). The pipelines' and hubs' construction activities are, to a limited extent, also subject to regulation under the Natural Gas Act of 1938 ("NGA"). The NGA also establishes comprehensive controls over interstate pipelines, including the transportation and resale of gas in interstate commerce. While these NGA controls do not apply directly to the Company, their effect on natural gas markets can be significant in terms of competition and cost of transportation services. The Federal Energy Regulatory Commission ("FERC") administers the NGA and the NGPA.
Through a series of orders, most recently the Order No. 636 Series, FERC has taken significant steps to increase competition in the sale, purchase, storage and transportation of natural gas. FERC's regulatory programs generally allow more accurate and timely price signals from the consumer to the producer and, on the whole, have helped natural gas to be more responsive to changing market conditions. Nonetheless, the ability to respond to market forces can and does add to price volatility, inter-fuel competition and pressure on the value of transportation and other services. The Order No. 636 Series was largely upheld by the United States Court of Appeals for the District of Columbia. Several parties have petitioned the Supreme Court to review the Court of Appeals' decision. It is uncertain whether the Supreme Court will agree to hear the case. Related orders under the Order No. 636 Series are the subject of numerous appeals to the United States Court of Appeals.
Through many interstate pipeline specific orders, the FERC has revised its policy regarding jurisdiction over gathering facilities and services. The FERC no longer asserts jurisdiction over these facilities and services and has stated that it is a matter to be left to the states for regulation. In 1996, the District of Columbia Court of Appeals largely upheld the FERC's policy. As a result of such court decision, the Texas Railroad Commission has begun initial inquiries regarding the scope of its regulation of gathering. The Company owns and operates extensive gathering systems in Texas. At this time, the Company cannot predict the extent to which any new Railroad Commission policy will affect its gathering activity. It is also possible that other states where the Company owns gathering facilities will become more active in the regulation of gathering.
As the owner of production area hubs and intrastate pipeline facilities in Wyoming and Texas, the Company also is subject to regulation by those states as to safety, rates and the provision of transportation services. As a seller of natural gas to end users, the Company also can be affected by state regulation of local distribution activities. While the extent of such state regulation varies, a number of states where the Company markets its natural gas are taking steps similar to steps taken by FERC to increase gas competition. As these programs take hold, direct access to local markets should increase, together with competitive pressures on prices and the value of distribution services.
Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. Several proposals that might affect the natural gas industry are pending before Congress and FERC. The Company cannot predict when or if any such proposals might become effective and their effect, if any, on the Company's operations. Historically, the natural gas industry has been heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC, Congress and the states will continue indefinitely into the future.
The oil and gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. Oil and gas exported from Canada is subject to regulation by the National Energy Board ("NEB") and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts meet certain criteria prescribed by the NEB and the government of Canada. Exports may be made pursuant to export contracts with terms not exceeding one year in the case of light crude oil and not exceeding two years in the case of heavy crude oil and natural gas, provided that an order approving any such export has been obtained from the NEB. Any export to be made pursuant to a contract of longer duration requires an NEB license and Governor in Council approval. The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations. In addition, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters.
It is not expected that any of these controls or regulations will affect the operations of the Company in a manner materially different than they would affect other oil and gas companies of similar size.
The Company's minerals operations are subject to a variety of Federal and state regulations with respect to safety, land use and reclamation. In addition, the Department of the Interior regulates the leasing of Federal lands for coal development as provided in the Mineral Lands Leasing Act of 1920.
SECTION 29 TAX CREDITS
Federal tax law provides an income tax credit against regular Federal income tax liability with respect to sales of the Company's production of certain fuels produced from nonconventional sources (including both coal seam natural gas and natural gas produced from tight sand formations), subject to a number of limitations ("Section 29 tax credits"). Fuels qualifying for the tax credit must be produced from a well drilled or a facility placed in service after December 31, 1979 and before January 1, 1993, and be sold before January 1, 2003.
The basic credit, which currently is approximately $0.52 per MMBtu of natural gas produced from tight sand reservoirs, is computed by reference to the price of crude oil and is phased out as the price of oil exceeds certain specified levels. The commencement of phaseout would be triggered if the average price for crude oil rose above approximately $45/Bbl in current dollars. The natural gas production from wells drilled on certain of the Company's properties in the Moxa Arch and Wamsutter areas in the Rockies, the Carthage field in East Texas, the Ozona field in West Texas and certain areas in the Austin Chalk trend qualifies for this tax credit. The Company recorded approximately $15.6 million of Section 29 tax credits in 1996. Section 29 tax credits are not creditable against the alternative minimum tax but under certain circumstances may be carried over and applied against regular tax liability in future years. Therefore, no assurance can be given that the Company's Section 29 tax credits will reduce its Federal income tax liability in any particular year.
In 1991 and 1992, the Company entered into transactions with a privately held company which provided funds for the Company to drill wells qualifying for Section 29 tax credits. Pursuant to these transactions, the Company conveyed much of its producing and tax credit eligible acreage in the Carthage field and Moxa Arch and Wamsutter areas to a limited partnership which, utilizing drilling funds contributed by the investor as limited partner, drilled 208 wells which qualify for Section 29 tax credits. The Company is the managing general partner of this producing partnership and has broad latitude in conducting operations on the assets therein. Prior to a defined payout, the limited partner was entitled to receive a preferential distribution of a specified quantity of available production from this partnership, including gas that did not qualify for the tax credits as well as tax credit-qualified gas. Payout occurred in December 1996, after which point the limited partner is entitled to receive only 1% of ongoing production. Both the historic and future forecasted production allocable to the limited partner have been deducted from the Company's reserve and production statistics.
TEXAS SEVERANCE TAX REDUCTION
Natural gas produced from wells that have been certified as tight formations or deep wells by the Texas Railroad Commission ("high cost wells") and that were spudded or completed during the period from May 24, 1989 to September 1, 1996 qualifies for an exemption from the 7.5% severance tax in Texas on natural gas and natural gas liquids produced by such wells ending August 31, 2001. The natural gas production from wells drilled on certain of the Company's properties in the Austin Chalk, West Texas and East/South Texas business units qualifies for this tax reduction. In addition, high cost wells that are spudded or completed during the period from September 1, 1996 to August 31, 2002 are entitled to receive a severance tax reduction. Operators have 180 days after first production to obtain a high cost gas certification. The tax reduction is based on a formula composed of the statewide "median" as determined by the State of Texas based on actual drilling and completion costs reported by producers. More expensive wells will receive a greater amount of tax credit. This tax rate reduction remains in effect for ten years or until the aggregate tax credits received equal 50% of the total drilling and completion costs.
ENVIRONMENTAL REGULATION
The Company's operations are subject to extensive Federal, state, provincial and local environmental laws and regulations governing the protection of the environment. The Company is in compliance, in all material respects, with applicable environmental requirements. Although future environmental obligations are not expected to have a material impact on the results of operations or financial condition of the Company, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause the Company to incur material environmental liabilities or costs.
Air Emissions. The primary legislation affecting the Company's air emissions is the Federal Clean Air Act and its 1990 Amendments (the "CAA"). Among other things, the CAA requires all major sources of air emissions to obtain operating permits; the amendments also revised the definition of a "major source" such that additional equipment involved in oil and gas production may now be covered by the permitting requirements. Although the precise requirements of Title III of the 1990 Amendments are not yet known, the Company may incur substantial expenditures for the additional capital, operating and maintenance costs required to comply with these new regulations.
Hazardous Substances and Waste Disposal. The Company currently owns or leases numerous properties that have been used for many years for hard minerals production or natural gas and crude oil production. Although the Company has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company. In addition, some of these properties have been operated by third parties over whom the Company had no control. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. The Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the disposal of "solid wastes" and "hazardous wastes." Although CERCLA currently excludes petroleum from its definition of hazardous substance, many state laws affecting the Company's operations impose clean-up liability regarding petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as "nonhazardous," such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. If such a change in legislation were to be enacted, it could have a significant impact on the Company's operating costs, as well as the oil and gas industry in general. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Environmental Costs."
Oil Spills. Under the Oil Pollution Act of 1990 ("OPA"), owners and operators of onshore facilities and pipelines and lessees or permittees of an area in which an offshore facility is located ("Responsible Parties") are strictly liable on a joint and several basis for removal costs and damages that result from a discharge of oil into United States waters. OPA limits the strict liability of Responsible Parties for removal costs and damages that result from a discharge of oil to $350 million in the case of onshore facilities and $75 million plus removal costs in the case of offshore facilities, except that these limits do not apply if the discharge was caused by gross negligence or willful misconduct, or by the violation of an applicable Federal safety, construction or operating regulation by the Responsible Party, its agent or subcontractor.
In addition, OPA requires certain vessels and offshore facilities to provide evidence of financial responsibility in the amount of $150 million. The MMS, which has jurisdiction over certain offshore facilities and pipelines, has not yet issued a proposed rule to implement the financial responsibility requirements and, therefore, the financial responsibility requirements applicable under laws existing prior to OPA still apply to such facilities. OPA also requires offshore facilities and certain onshore facilities to prepare facility response plans, which the Company has done, for responding to a "worst case discharge" of oil. Failure to comply with these requirements or failure to cooperate during a spill event may subject a Responsible Party to civil or criminal enforcement actions and penalties.
Offshore Production. Offshore oil and gas operations are subject to regulations of the United States Department of the Interior which currently impose strict liability upon the lessee under a Federal lease for the cost of clean-up of pollution resulting from the lessee's operations, and such lessee could be subject to possible
liability for pollution damages. In the event of a serious incident of pollution, the Department of the Interior may require a lessee under Federal leases to suspend or cease operations in the affected areas.
Canadian Environmental Regulation. The oil and gas industry in Canada currently is subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties. In Alberta, environmental compliance has been governed by the Alberta Environmental Protection and Enhancement Act ("AEPEA") since September 1, 1993. In addition to replacing a variety of older statutes which related to environmental matters, AEPEA also imposes certain new environmental responsibilities on oil and natural gas operators in Alberta and, in certain instances, imposes greater penalties for violations. In British Columbia, regulations affecting the oil and gas industry are administered by the Ministry of Energy, Mines and Petroleum Resources.
EMPLOYEES
The Company had 1,584 employees as of December 31, 1996. The Company believes that its relations with its employees are good.
OTHER BUSINESS MATTERS
The Company's operations are subject to the usual hazards incident to the drilling and operation of oil and gas wells and the processing and transportation of natural gas and natural gas liquids, such as cratering, explosions, uncontrollable flows of oil, gas or well fluids, fire, pollution and other environmental risks. In general, many of these risks increase when drilling at greater depths under higher pressure conditions. In addition, certain of the Company's operations are currently offshore and subject to the additional hazards of marine operations, such as capsizing, collision and damage or loss from severe weather. Other operations involve the production, handling, processing and transportation of gas containing hydrogen sulfide and other hazardous substances. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, environmental damage and suspension of operations. Litigation arising from a catastrophic occurrence in the future at one of the Company's locations may result in the Company being named as a defendant in lawsuits asserting potentially large claims. In accordance with customary industry practices, insurance is maintained for the Company against some, but not all, of the consequences of these risks. Losses and liabilities arising from such events could reduce revenues and increase costs to the Company to the extent not covered by insurance or already provided for.
ITEM 2.

ITEM 2. PROPERTIES
PROVED RESERVES
The following table sets forth the proved developed and undeveloped reserves of natural gas, natural gas liquids and crude oil of the Company as of December 31, 1996. Information set forth in the table is based on reserve estimates of the Company, prepared in accordance with the rules and regulations of the Securities and Exchange Commission.
There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company. The reserve data set forth herein represent estimates only. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
ACREAGE
Land Grant and Other Fee Minerals. The following table summarizes the fee mineral acreage by business unit owned by the Company as of December 31, 1996.
The Company holds royalty interests of varying percentages in the approximately one million gross acres of the Land Grant that are subject to exploration and production agreements with third parties. The Company's fee mineral acreage is primarily undeveloped.
Leasehold. The Company's leasehold acreage by business unit as of December 31, 1996 is set forth below.
Total Leasehold and Fee Mineral. The total leasehold and fee mineral acreage by business unit as of December 31, 1996 is set forth below.
DRILLING ACTIVITY AND PRODUCING WELL SUMMARY
The table below summarizes the Company's drilling activity over the last three years.
The number of wells drilled is not a valid measure or indicator of the relative success or value of a drilling program because the significance of the reserves and their economic potential may vary widely for each project. As of December 31, 1996, the Company owned interests in 5,011 gross gas wells (2,703 net) and 2,786 gross oil wells (1,620 net). Gross wells include 577 wells with multiple completions. The Company operated 59% of the gross wells in which it owned an interest.
GAS PROCESSING ASSETS
A listing of the Company's processing plants as of December 31, 1996 is provided below.
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* Nonoperated
(1) Represents the gross design capacity of the gas plant as of December 31, 1996.
(2) Includes 50 MMcfd of design capacity which came on-line in 1996.
(3) Design capacity includes 260 MMcfd utilized for field pressure maintenance. During 1995, pressure maintenance ceased, resulting in current processing capacity of 390 MMcfd. As a result, an additional 80 MMcfd from the Anschutz Ranch field normally processed at this plant currently is being processed at Painter complex.
(4) Financial and operating statistics are included in the producing property, rather than the plants, pipelines and marketing disclosures (the plant is accounted for as a lease facility).
(5) Residue gas can be reinjected for pressure maintenance.
(6) Sour gas facility (capable of processing gas containing hydrogen sulfide).
(7) Includes fractionation facilities.
(8) Nitrogen is reinjected for pressure maintenance.
(9) Includes 30 MMcfd of design capacity which came on-line in May 1996.
(10) Straddle plants which process gas gathered by the Ferguson-Burleson County Gas Gathering System.
(11) Straddle plant (a plant located near a transmission facility which processes gas dedicated to or gathered by a third party).
Average throughput in these plants for 1996 was approximately 84% of design capacity.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
In August 1994, the surface owners of portions of five sections of Colorado land that are subject to mineral reservations made by the Company's predecessor in title brought suit against the Company in the District Court of Weld County, Colorado, to quiet title to minerals, including crude oil (in some of the lands) and natural gas. In September 1994, the case was removed to the United States District Court for the District of Colorado. The Company plans to file a motion for summary judgment asking the state court to rule as a
matter of law that it owns the oil and gas and all minerals that are part of a severed mineral estate. No trial date currently is set. Similar claims were made under identical mineral reservations by Utah and Wyoming surface owners in cases litigated in the Federal courts of Utah and Wyoming between 1979 and 1987. In those cases, the Federal courts held as a matter of law that, under the laws of Utah and Wyoming, these mineral reservations unambiguously reserved oil and gas to Union Pacific Railroad Company and its successors. These holdings were affirmed by the United States Court of Appeals for the Tenth Circuit. While the Company believes that the rule of law applied by the Federal courts in Utah and Wyoming also should be applied under Colorado law, there are Colorado court decisions that could provide a basis for an alternative interpretation. The value of the disputed reserves in the properties subject to the lawsuit is estimated to be approximately $5 million. Approximately 400,000 acres of other lands in Weld County, Colorado, are subject to mineral reservations that are in the same form as the reservations at issue in the present suit. An adverse interpretation of the reservations at issue is likely to implicate the mineral title in these other lands as well. In addition, over two million acres of lands elsewhere in Colorado are subject to the same forms of mineral reservations. Depending on the grounds of an adverse decision in the case, title to minerals held by the Company in some or all of these lands also could be affected, which might have the effect of significantly reducing the Company's interest in the Las Animas area of southeastern Colorado and the Denver-Julesburg Basin in eastern Colorado.
The Company is a defendant in three contract suits now pending in Fayette County, Lee County and Harris County (transferred from Calhoun County), Texas, in which the plaintiffs allege that the Company underpaid their royalties for crude oil production in Texas. Plaintiffs seek certification as a class action in each suit. The Texas General Land Office is a plaintiff in the Fayette County suit (filed August 1995). The allegations are premised upon plaintiffs' theory that the defendants (including the Company) use "posted prices" to determine the amounts payable as royalties for crude oil production. Plaintiffs allege that the defendants "set" these posted prices, that posted prices are consistently below "market value," and that this practice has resulted in the underpayment of royalties to plaintiffs.
The Company also is one of the defendants in an antitrust suit filed in September 1996 in the Circuit Court of Escambia County, Alabama, against a number of crude oil producers alleging that the use of posted prices by defendants to pay royalties on crude oil produced in the United States arises from a combination, conspiracy or agreement designed to fix, depress and maintain such crude prices at artificially low levels. The plaintiffs have received a "conditional" certification as a class action on behalf of all working and royalty interest owners of crude oil produced in the United States since 1986 who have been paid by defendants based on posted prices. The suit was removed to Federal court, United States District Court, Southern District, Mobile, Alabama Division, on October 17, 1996. Plaintiffs' motion to remand the suit back to the Circuit Court is pending. Defendants' motion to transfer the suit to Houston also is pending.
None of these suits described above articulate a theory of recovery or a specific amount of damages. This litigation activity against the Company and others in the oil and gas industry suggests that more suits of this type may be filed against the Company including, perhaps, suits by other types of interest owners and in jurisdictions other than Texas and Alabama. The Company intends to defend vigorously against the foregoing, as well as any similar suits. If such suits ultimately are resolved against the Company on a widespread basis, however, damage awards and a loss of future revenue could result which, in the aggregate, could be materially adverse to the Company.
The Company is a defendant in a number of lawsuits and is involved in governmental proceedings arising in the ordinary course of business in addition to those described above, including personal injury claims and environmental claims. While the Company cannot predict the outcome of such litigation and other proceedings, it does not expect those matters to have a materially adverse effect on its results of operations or financial condition.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the quarter ended December 31, 1996.
EXECUTIVE OFFICERS OF THE REGISTRANT
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(1) Mr. Messman has been Chairman and Chief Executive Officer of the Company since October 1996. He was President and Chief Executive Officer of the Company from August 1995 to October 1996, and has been a Director of the Company since September 1991. He has been President, Chief Executive Officer and a Director of UPRC since May 1991.
(2) Mr. Lindahl has held his current position with the Company since October 1996. He was Executive Vice President -- Operations of the Company from August 1995 to October 1996. From 1992 to August 1995, he was Vice President -- Operations for UPRC. Prior thereto, he was Vice President -- Exploration for UPRC.
(3) Mr. Eales has held his current position with the Company since June 1996. From August 1995 to June 1996, he was Executive Vice President and Chief Financial Officer of the Company. Prior thereto, he was Vice President -- Corporate Development of UPRC.
(4) Ms. Franklin has held her current position with the Company since August 1995. She joined UPRC as Vice President -- People in June 1995. From 1993 to June 1995, she was Director of Executive Leadership and Development for Ameritech, Inc. Prior thereto, she held various positions in marketing and operations at Indiana Bell Telephone Company (currently Ameritech).
(5) Mr. Knouse has held his current position with the Company since August 1995. Prior thereto, he was Vice President -- Government Relations and Public Affairs of UPRC.
(6) Mr. LaSala has held his current position with the Company since January 1996. Mr. LaSala joined UPRC in January 1995 as Assistant General Counsel. He was Vice President -- Government and Regulatory Affairs of USPCI, Inc., a former subsidiary of UPC, from May 1993 until December 1994 and, prior thereto, Vice President -- External Relations of USPCI.
(7) Mr. Niemiec has held his current position with the Company since August 1995. He has been Vice President -- Marketing of UPRC since 1993 and President of UP Fuels since 1990.
(8) Mr. Smith has held his current position with the Company since June 1996. From September 1995 until June 1996, he was Vice President and Controller of UPC. From January through August 1995, he served as Vice President -- Finance of Union Pacific Railroad Company; from June 1993 through December 1994, he served as Vice President -- Finance of USPCI, Inc. Prior thereto, he was Assistant Controller -- Planning and Analysis of UPC.
(9) Mr. Vering has held his current position with the Company since October 1996. Prior thereto, he was General Manager -- Austin Chalk of the Company and UPRC.
PART II
ITEM 5.

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company completed an initial public offering of its common stock in October 1995. The common stock of the Company is traded on the New York Stock Exchange under the symbol "UPR." Information with respect to the quarterly high and low sales prices per share for the Company's common stock, as reported on the New York Stock Exchange Composite Tape, as well as the dividends declared on such stock, is set forth under Selected Quarterly Data on page 62.
At February 25, 1997, there were 253,776,970 shares of outstanding common stock and approximately 58,000 shareholders of record. At that date, the closing price of the common stock on the New York Stock Exchange was $24.63.
The Company has paid quarterly cash dividends of $0.05 per share since its initial public offering. The Company currently intends to continue to pay quarterly cash dividends on its outstanding shares of common stock. The determination of the amount of future cash dividends, if any, to be declared and paid by the Company will depend upon, among other things, the Company's financial condition, funds from operations, the level of its capital and exploratory expenditures, future business prospects and other factors deemed relevant by the Board of Directors. Accordingly, there can be no assurance that dividends will be paid.
In October 1996, the Board of Directors adopted a shareholder rights plan with a "flip-in" threshold of 15% to ensure that all shareholders of the Company receive fair value for their common stock in the event of any proposed takeover of the Company and to guard against the use of coercive tactics to gain control of the Company without offering fair value to the Company's shareholders. In February 1997, the Board of Directors adopted a stock repurchase program which authorizes the Company to purchase up to $50 million of its common stock outstanding in any given fiscal year.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
FIVE-YEAR FINANCIAL SUMMARY
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(a) In November 1995, the Company recorded a $122.5 million pre-tax ($78.5 million after-tax) gain resulting from the Columbia Gas Transmission Company bankruptcy settlement (see Note 4 to the Consolidated Financial Statements).
(b) In January 1993, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," and SFAS
No. 109, "Accounting for Income Taxes," with a cumulative after-tax charge to 1993 earnings of $59 million.
(c) In March 1994, the Company sold its interest in the Wilmington Field and Harbor Cogeneration Plant to the Port of Long Beach, California. The Wilmington sale resulted in a $159.2 million pre-tax ($100 million after-tax) gain (see Note 4 to the Consolidated Financial Statements).
(d) Earnings per share prior to 1996 have been omitted as the Company was a wholly owned subsidiary of UPC until the Offering in October 1995. Therefore, net income per share is not applicable for periods prior to the fourth quarter of 1995. See "Selected Quarterly Data" on page 62.
(e) Represents the dividend declared with respect to the fourth quarter of 1995. Prior to October 1995, the Company was wholly owned by UPC. Therefore, dividends per share is not applicable for periods prior to the fourth quarter of 1995.
(f) In March 1994, the Company acquired Amax Oil & Gas, Inc., for a net purchase price of $725 million.
(g) During 1996, the Company repaid its $650 million note payable to UPC (incurred at the time of the Offering) using cash from operations and proceeds from the issuance of long-term debt and commercial paper (see Note 8 to the Consolidated Financial Statements).
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following information should be read in conjunction with the information contained in the Consolidated Financial Statements and the notes thereto included in Item 8

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
RESPONSIBILITIES FOR FINANCIAL STATEMENTS
The accompanying financial statements, which consolidate the accounts of Union Pacific Resources Group Inc. and its subsidiaries, have been prepared in conformity with generally accepted accounting principles.
The integrity and objectivity of data in these financial statements and accompanying notes, including estimates and judgments related to matters not concluded by year-end, are the responsibility of management, as is all other information in this report. Management devotes ongoing attention to review and appraisal of its system of internal controls. This system is designed to provide reasonable assurance, at an appropriate cost, that the Company's assets are protected, that transactions and events are recorded properly and that financial reports are reliable. The system is augmented by a staff of internal auditors; careful attention to selection and development of qualified financial personnel; programs to further timely communication and monitoring of policies, standards and delegated authorities; and evaluation by independent auditors during their examinations of the annual financial statements.
The Audit Committee of the Board of Directors, composed of six non-employee directors, meets regularly with financial management, the internal auditors and the independent auditors to review financial reporting and accounting and financial controls of the Company. Both the independent auditors and the internal auditors have unrestricted access to the Audit Committee and meet regularly with the Audit Committee, without financial management representatives present, to discuss the results of their examinations and their opinions on the adequacy of internal controls and quality of financial reporting.
JACK L. MESSMAN Chairman and Chief Executive Officer
MORRIS B. SMITH Vice President and Chief Financial Officer
JOHN E. JACKSON Controller and Chief Accounting Officer
INDEPENDENT AUDITORS' REPORT
To the Board of Directors Union Pacific Resources Group Inc. Fort Worth, Texas
We have audited the accompanying consolidated statements of financial position of Union Pacific Resources Group Inc. (the "Company") as of December 31, 1995 and 1996, and the related consolidated statements of income, changes in shareholders' 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, such consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 1995 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Fort Worth, Texas January 29, 1997
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
The accompanying accounting policies and notes to the consolidated financial statements are an integral part of these statements.
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION AS OF DECEMBER 31, 1995 AND 1996
ASSETS
The accompanying accounting policies and notes to the consolidated financial statements are an integral part of these statements.
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
The accompanying accounting policies and notes to the consolidated financial statements are an integral part of these statements.
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
The accompanying accounting policies and notes to the consolidated financial statements are an integral part of these statements.
UNION PACIFIC RESOURCES GROUP INC.
BUSINESS SEGMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
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(a) Includes items such as unallocated working capital and intangible and other assets.
This information should be read in conjunction with the accompanying accounting policies and notes to the consolidated financial statements.
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation. The Consolidated Financial Statements include the accounts of Union Pacific Resources Group Inc. and subsidiaries, including its principal operating subsidiary Union Pacific Resources Company ("UPRC"). These operations are hereinafter referred to collectively as the "Company." The Company accounts for investments in affiliated companies (20% to 50% owned) on the equity method of accounting and consolidates its proportionate share of oil and gas ventures. All material intercompany transactions are eliminated. The consolidated statements of income for previous periods include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no effect on previously reported operating income or net income.
Cash and Temporary Investments. Temporary investments are stated at cost which approximates fair market value, and consist of investments with original maturities of three months or less.
Inventories. Inventories consist primarily of hydrocarbon volumes and materials and supplies carried on a first-in first-out basis at the lower of cost or market.
Oil and Gas Properties. Oil and gas properties are accounted for using the successful efforts method. Under this method, drilling costs of unsuccessful exploration wells, geological and geophysical costs, non-producing leasehold amortization and delay rentals are charged to expense when incurred. Costs to develop producing properties, including drilling costs and applicable leasehold acquisition costs, are capitalized.
Depreciation, depletion and amortization of producing properties, including depreciation of well and support equipment and amortization of related lease costs, are determined by using a unit of production method based upon estimated proved reserves. Acquisition costs of unproved properties are amortized from the date of acquisition on a composite basis, which considers past success experience and average lease life. Provisions for depreciation of property and equipment other than producing properties are computed principally on the straight-line method based on estimated service lives, which range from three to 30 years.
Costs of future site restoration, dismantlement and abandonment for onshore producing properties are accrued (based on internal engineering estimates) as part of depreciation, depletion and amortization expense for tangible equipment by assuming no salvage value in the calculation of the unit of production rate. Costs of future site restoration, dismantlement and abandonment for offshore wells and production platforms also are accrued based on internal engineering estimates using the unit of production method with a charge to depreciation, depletion and amortization expense. The balance of the offshore abandonment accrual at December 31, 1995 and 1996 was $13.1 million and $6.2 million, respectively, and is classified in other long-term liabilities.
Potential impairment of producing properties and significant unproved properties is assessed annually (unless economic events warrant more frequent reviews) on a field-by-field basis; all other unproved properties are assessed annually on an aggregate basis. In addition, a quarterly impairment analysis of aggregated properties is performed by the Company using undiscounted future net cash flows determined based upon current prices and costs.
Costs of retired, sold or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless such nonrecognition would significantly affect the unit of production rate. Gains or losses from the disposition of other properties are recognized currently. Gains and losses from the sale of operating assets that constitute an entire profit center and significant nonoperating assets are recorded in other income. Gains and losses from all other dispositions of operating assets are recognized in other oil and gas revenues.
Goodwill. Intangible and other assets includes goodwill of $68.6 million arising from business combinations prior to 1971. Such goodwill is not being amortized because it is considered to have continuing value over an indefinite period. Goodwill is reviewed periodically to determine whether any potential impairment exists.
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Revenue Recognition. Sales from producing gas wells are recognized on the entitlement method of accounting which defers recognition of sales and related costs when, and to the extent that, deliveries to customers exceed the Company's net revenue interest in production. Similarly, when deliveries are below the Company's net revenue interest in production, sales and related costs are recorded to reflect the full net revenue interest.
Marketing revenue included in plants, pipelines and marketing revenues is recorded net of the cost of hydrocarbons purchased.
Hedging Transactions. The Company uses hydrocarbon-based derivative financial instruments from time to time to reduce risks associated with hydrocarbon price volatility. Gains and losses from hedging transactions generally are recognized at delivery of the commodity. However, when correlation between the derivative contract price and the price of the underlying commodity falls below 80%, affected derivative positions are marked to market, with the resulting gain or loss recognized immediately in income (see Note 5).
Income Taxes. Deferred income taxes are provided for items of income and expense that are included in income for financial reporting purposes in different reporting periods than for Federal income tax purposes.
Until its spinoff from Union Pacific Corporation ("UPC") in October 1996 (see Note 2), the Company was included in UPC's consolidated income tax return. The consolidated income tax liability of UPC through such date has been allocated among its affiliated companies on the basis of their separate contributions to the consolidated income tax liability, with full benefit of tax losses and credits utilized in consolidation being allocated to the individual companies generating such losses and credits.
Stock-Based Compensation. Compensation expense is recorded with respect to stock option grants and retention stock awards to employees using the intrinsic value method. This method calculates compensation expense on the measurement date (usually the date of grant) as the excess of the current market price of the underlying Company stock over the amount the employee is required to pay for the shares, if any. The expense is recognized over the vesting period of the grant or award.
Earnings Per Share. Earnings per share for 1996 is based upon 250,077,716 weighted average common shares outstanding during the period, including shares issuable upon exercise of outstanding stock options determined using the treasury stock method.
Earnings per share for the years ended December 31, 1994 and 1995 have been omitted from the Consolidated Statements of Income as the Company was a wholly owned subsidiary of UPC until its initial public offering in October 1995. Pro forma 1995 earnings per share (see Note 2) and fourth quarter 1995 earnings per share (see page 62) are based upon 249.7 million average common shares outstanding during the period from completion of the Offering (hereinafter defined) until December 31, 1995.
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 certain 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 each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties which may cause actual results to differ materially from the Company's estimates. Significant estimates underlying these financial statements include the estimated quantities of proved oil and gas reserves and the related present value of estimated future net cash flows therefrom (see Supplementary Information beginning on page 57).
Recently Issued Accounting Standards. The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants has adopted Statement of Position 96-1, "Environmental Remediation Liabilities," which provides guidance on the recognition, measurement, display and disclosure of environmental remediation liabilities. The statement is effective for the Company's 1997 fiscal year.
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Management has evaluated such statement and believes that it will not have a material effect on the financial condition or results of operations of the Company.
1. NATURE OF OPERATIONS
The Company is an independent energy company engaged primarily in the exploration for and development and production of natural gas, natural gas liquids and crude oil principally in the United States. The Company owns and operates significant assets, in proximity to its principal producing properties, dedicated to the gathering, processing and transportation of natural gas and natural gas liquids. The Company markets a substantial portion of its own natural gas, natural gas liquids and crude oil production together with significant volumes of natural gas, natural gas liquids and crude oil produced by others. The Company has a diverse customer base for its hydrocarbon products. In addition, the Company engages in the hard minerals business through nonoperated joint venture and royalty interests in several coal and trona (natural soda ash) mines.
The Company's results of operations are largely dependent on the difference between the prices received for its hydrocarbon products and the cost to find, develop, produce and market such resources. Hydrocarbon prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond the control of the Company. These factors include worldwide political instability, the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand and the price and availability of alternative fuels. Historically, the Company has been able to manage a portion of the operating risk relating to hydrocarbon price volatility through hedging activities (see Note 5).
2. SPINOFF FROM UNION PACIFIC CORPORATION
In October 1995, the Company sold 42.5 million shares of its common stock in an initial public offering (the "Offering") at an offering price of $21 per share. Prior to consummation of the Offering, the Company was wholly owned by UPC. Following the Offering and until October 15, 1996, UPC owned approximately 83% of the Company's outstanding common stock. Concurrent with the Offering, UPC announced its intention to distribute its remaining ownership interest in the Company to its shareholders as a dividend by means of a tax-free distribution (the "Distribution"). On October 15, 1996, the Distribution was consummated.
Prior to the Offering (1) UPC caused the Company to own all the rights and assets historically employed by the natural resources business segment of UPC in connection with the operations presented in the Consolidated Financial Statements and (2) the Company declared dividends to UPC totaling $1,621 million consisting of (i) a cash dividend of $912 million payable promptly after the completion of the Offering, (ii) a $650 million note payable to UPC bearing interest at 8.5% per annum payable within 90 days of the Distribution and (iii) a $59 million receivable from UPC. The Company borrowed $68 million which was used, together with the $843.9 million net proceeds from the Offering, to pay the cash dividend of $912 million. Such transactions, referred to collectively as the "Asset Restructuring," are reflected in the Consolidated Financial Statements as of December 31, 1995 and thereafter.
As a result of the Offering and related transactions, historical results of operations are not directly comparable to results for the year ended December 31, 1996. The following pro forma information reflects
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
adjustments to the historical 1995 Consolidated Statement of Income necessary to give effect to the Asset Restructuring and the Offering as if such transactions had occurred at the beginning of 1995.
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(a) Adjustment to reflect management's estimate of additional administrative and third party costs that the Company is incurring as a result of becoming a stand-alone public company. These costs include (1) additional administrative personnel, (2) additional third party fees such as audit fees, actuarial fees, legal fees and stock transfer fees, (3) additional annual stock compensation costs related to employee retention shares (see Note 11) and (4) fees payable to UPC for certain financial guarantees provided to the Company.
(b) Adjustment to eliminate intercompany interest income recorded by the Company during the period, as a result of the dividend to UPC of the $59 million intercompany receivable.
(c) Adjustment to reflect increased interest expense from the $650 million note payable to UPC at 8.5% per annum and $68 million in bank debt at 6.1% per annum, which debt was incurred to pay a portion of the $912 million cash dividend to UPC.
(d) Adjustment to reflect decreased Federal and state income tax expense resulting from increased expenses in entries (a) through (c) above, calculated at an assumed income tax rate of 37.5%.
(e) See "Significant Accounting Policies -- Earnings Per Share."
In addition, reported 1996 results include approximately $2.0 million of pension expense representing one quarter of approximately $8.0 million additional annual pension expense associated with the October 1996 allocation of pension assets between the Company and UPC (see Note 10).
3. RELATED PARTY TRANSACTIONS
At December 31, 1995, the Company had a $567.8 million net payable to UPC at 8.5%, reflecting the $650 million note payable incurred in connection with the Asset Restructuring (see Note 2), partially offset by $82.2 million in cash advances to UPC. Such intercompany debt was repaid in part during 1996 using cash from operations with the remainder repaid immediately following the Distribution using proceeds from the issuance of long-term debt and commercial paper (see Note 8). Intercompany interest income related to amounts receivable from UPC was $15.8 million and $9.6 million in 1994 and 1995, respectively, which is included in other income in the Company's Consolidated Statements of Income. Intercompany interest expense related to amounts payable to UPC after the Offering was $14.5 million in 1995 and $32.6 million in 1996 which is included in interest expense in the Company's Consolidated Statements of Income.
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Services historically performed by UPC on behalf of the Company included services in the areas of cash management, internal audit and tax and employee benefits administration. Prior to the Offering, the cost of such services, which is not significant, was not charged to the Company. As a result of the Asset Restructuring and the Offering, UPC and the Company entered into a number of agreements for the purpose of defining the ongoing relationship between them. Costs incurred by the Company in 1995 and 1996 related to such agreements were $0.9 million and $2.7 million, respectively, principally reflecting the cost of administrative services and certain financial guarantees. In connection with the Distribution, most of these agreements with UPC have been terminated and the terms of any ongoing agreements between the Company and UPC have been amended as a result of arm's length negotiations. The financial impact of any ongoing agreements is not expected to be significant.
4. SIGNIFICANT ITEMS
Columbia Gas Transmission Company. In November 1995, the Company received a cash payment from Columbia Gas Transmission Company ("Columbia") as a part of Columbia's emergence from Chapter 11 bankruptcy. An issue remains as to whether the payment received is royalty bearing, other than that portion of the payment applicable to gas actually produced and sold to Columbia, and the Company has instituted a legal proceeding to obtain a declaration of its rights and obligations. As a result of the payment from Columbia, after taking into account possible tax and royalty claims, the Company recorded pre-tax income of $122.5 million in the fourth quarter of 1995 ($78.5 million after tax) which is included in other oil and gas revenues in the Company's 1995 Consolidated Statement of Income. During 1996, the Company reached settlements or took default judgment with respect to a number of royalty owners named in the suit. The Company also made a determination and payment of its severance tax liability. As a result, in the fourth quarter of 1996, the Company recognized $31.3 million in other oil and gas revenues related to a reduction in its litigation and contingencies accrual pertaining to the Columbia payment (see Note 15).
Amax Oil & Gas, Inc. In March 1994, the Company acquired Amax Oil & Gas, Inc. ("Amax") for $725 million. Amax's operations consisted principally of natural gas producing properties and related processing and transportation facilities, located primarily in western and southern Texas and Louisiana. At the date of acquisition, these properties included interests in 14 major fields, encompassing over 500,000 acres and approximately 2,000 producing wells. The Company initially recorded 550 Bcfe of proved reserves related to the Amax acquisition.
Wilmington Field Sale. In March 1994, the Company sold its interest in the Wilmington, California, field and the Harbor Cogeneration Plant to the Port of Long Beach, California. Proceeds from the sale consisted of $280 million in cash and two interest-bearing notes of $62.5 million each which subsequently have been collected. The Wilmington sale resulted in a $159.2 million pre-tax ($100 million after-tax) gain. Such pre-tax gain is included in other income in the Company's 1994 Consolidated Statement of Income. The sale of the Wilmington hydrocarbon reserves (approximately 3% of the Company's year end 1993 proved reserves) has not significantly affected the Company's ongoing operating results.
As part of the Wilmington sales agreement, the Company agreed to participate with the Port of Long Beach in funding environmental remediation and site preparation, as specified by the Port of Long Beach, up to a maximum of $105.5 million. As a result, the determination of the gain on the sale of the Wilmington properties included provisions of $50.5 million for future environmental costs and $55.0 million for future site preparation costs ($97.9 million in total remaining at December 31, 1996) categorized as other current and long-term liabilities (see Notes 13 and 15). The majority of cash outlays for these liabilities is expected to occur over the next five years.
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. FINANCIAL INSTRUMENTS
Hedging. The Company uses hydrocarbon-based derivative financial instruments from time to time to reduce risks associated with hydrocarbon price volatility. While the use of these hedging arrangements may limit the downside risk of adverse price movements, it may also limit future gains from favorable movements. Hedging generally is accomplished pursuant to exchange-traded futures contracts or master swap agreements based on standard forms. Hedging gains and losses are deferred and recognized at delivery of the commodity. The Company does not hold or issue derivative financial instruments for trading purposes and does not hedge any significant amount of production beyond a 24-month time frame. In connection with its futures contract hedging activity, the Company is required to deposit monies with the New York Mercantile Exchange ("NYMEX"), representing cash requirements for contract margins and deposits for unrealized losses on open contracts. Such deposits are included in other current assets in the Company's Consolidated Statements of Financial Position. At December 31, 1996, the Company had margin requirements totaling $44.7 million, which were met with cash deposits of $30.9 million and unrealized gains on open contracts of $13.8 million. Deferred losses on other derivative positions, primarily representing January hedges deferred as of December 31, were $17.1 million at December 31, 1996, and are included in other current assets in the Company's Consolidated Statement of Financial Position.
The Company addresses market risk by selecting hydrocarbon-based derivative financial instruments whose historical value fluctuations correlate with those of the item being hedged, so that gains or losses on the financial instruments will be substantially offset by gains or losses on the hedged item. Basis risk, which arises from differences between wellhead prices in the Company's specific producing locations and the underlying NYMEX prices contained in the financial instruments, is managed by using basis swaps in combination with futures contracts and price swaps. In December 1995, the Company recorded an $8.1 million pre-tax ($5.3 million after-tax) charge relating to loss of correlation between NYMEX prices and the actual wellhead prices ultimately received by the Company for a portion of its first quarter 1996 hedged natural gas production. Such loss was included as a reduction in other oil and gas revenues in the Company's 1995 Consolidated Statement of Income.
The Company is exposed to credit losses in the event of nonperformance by its counterparties. Credit risk related to hedging activities is managed by requiring that counterparties meet certain minimum credit standards and by conducting mark-to-market analysis to review potential exposure and determine if collateral is required. At December 31, 1996, the largest credit risk associated with any of the Company's counterparties, representing the fair value of contracts with a positive net fair value at the reporting date, was approximately $4.0 million. The Company anticipates that its counterparties, which consist principally of organized exchanges, major financial institutions and large dealers, will be able to satisfy their obligations related to the Company's contracts.
At December 31, 1996, the Company had near-term futures contracts and price swaps for February through December 1997 with respect to natural gas volumes of 696 MMcfd at $2.06/Mcf. The unrecognized mark-to-market gain associated with such contracts, representing the price the Company would receive to close such contracts at the reporting date, was $23.7 million. With respect to crude oil, at December 31, 1996, the Company had near-term NYMEX-related contracts for January through December 1997 with respect to crude oil volumes of 20 MBbld at $20.23/Bbl, with an unrecognized mark-to-market loss of $19.8 million. Additionally, the Company has simultaneously purchased commodity put options (floor) and sold commodity call options (ceiling), the combination of which has the effect of establishing a minimum and maximum price the Company would receive for its crude oil. At December 31, 1996, the Company had established a floor of $19.17/Bbl (including net premium paid) and a ceiling of $24.67/Bbl (including net premium paid) with respect to 25.0 MBbld of crude oil for January through December 1997. The Company will continue to receive current market prices for its crude oil as long as market prices remain within the range established by the floor and the ceiling. The fair value of such options at December 31, 1996 was a negative
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$1.8 million, representing the net cost to repurchase the options given current market prices using an option pricing model. Net option premiums, which are included in other current assets in the Company's Consolidated Statements of Financial Position, are deferred and recognized in income as the related volumes are produced.
Also at December 31, 1996, the Company had near-term futures contracts and price swaps for January through December 1998 with respect to natural gas volumes of 37 MMcfd at $2.21/Mcf. The unrecognized mark-to-market gain associated with such contracts was $0.7 million.
The Company also enters into long-term fixed price sales agreements for physical deliveries of natural gas, and at December 31, 1996, had outstanding contracts relating to 81.5 Bcf of natural gas for periods through December 31, 2008. Average annual commitments during this period would have comprised no more than 2% of the Company's 1996 natural gas sales volumes. Such long-term commitments are not reflected in the Company's Consolidated Statements of Financial Position. The Company's marketing subsidiary, Union Pacific Fuels, Inc. ("UP Fuels"), enters into long-term financial contracts that, in combination with these long-term fixed price sales agreements, secure a margin on the corresponding volume positions. At December 31, 1996, long-term fixed price sales commitments for which corresponding financial positions had not been entered into totaled 69.8 Bcf at an average price of $2.95/Mcf, with a positive fair value of $26.6 million. The remaining commitments for 11.7 Bcf had been offset with financial contracts for similar volumes. The unrecognized mark-to-market present value related to such hedged commitments at December 31, 1996 comprises a $0.2 million loss on the long-term fixed price sales commitments and a $1.3 million gain on the corresponding financial contracts.
At December 31, 1996, the Company had a total unrecognized mark-to-market present value gain of $30.5 million related to the financial and fixed price sales contracts described above. Such gain comprises a $26.4 million net gain on contracts for physical delivery and a $4.1 million net gain on financial contracts. Unrecognized mark-to-market gains or losses were determined based upon current market value, as quoted by recognized dealers, assuming a round lot transaction and using a mid-market convention without regard to market liquidity.
As a result of its hedging program, the Company's oil and gas revenues can be higher or lower than revenues that would be reported if hedging did not occur. During 1994 and 1995, revenues were $36 million and $27 million higher, respectively, while during 1996, revenues were $52 million lower as a result of hedging activities.
Fair Value of Financial Instruments. At December 31, 1996, the carrying value of the Company's long-term debt approximates its fair market value, estimated using current borrowing rates. The carrying value of all other financial instruments also approximates fair market value.
Concentrations of Credit Risk. Financial instruments which subject the Company to concentrations of credit risk consist principally of trade receivables and short-term cash investments. The Company places its temporary excess cash investments in high quality short-term instruments through several high credit quality financial institutions. A significant portion of the Company's trade receivables relate to customers in the oil and gas industry, and, as such, the Company is directly affected by the economy of that industry. However, the credit risk associated with trade receivables is minimized by the Company's large customer base and ongoing procedures to monitor the creditworthiness of customers. The Company generally requires no collateral from its customers. Historically, the Company has not experienced significant losses on trade receivables.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. PROPERTIES
Major property classifications as of December 31 are as follows:
Accumulated depreciation, depletion and amortization by major property classifications is as follows:
Based upon the Company's analysis of expected future net cash flows from its oil and gas properties, certain properties were deemed to be impaired following recent downward revisions in reserve estimates. Accordingly, in the fourth quarter of 1996, the Company adjusted the net book value of such properties to their fair value, determined using a discounted cash flow approach, with a charge to operations of $34.4 million.
Fixed asset additions included capitalized interest of $0.9 million in 1994, $1.0 million in 1995 and $0.2 million in 1996.
7. INCOME TAXES
Components of income tax expense are as follows:
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Deferred tax liabilities (assets) as of December 31 include the following:
A reconciliation between statutory and effective tax rates is as follows:
The Company generates Section 29 tax credits from the sale of certain fuels produced from nonconventional sources. Fuels qualifying for the credit must be produced from a well drilled or a facility placed in service after December 31, 1979 and before January 1, 1993, and sold before January 1, 2003. The Company generated $52.2 million, $39.9 million and $15.6 million of Section 29 tax credits in 1994, 1995 and 1996, respectively. The Federal tax law provides for the use of these credits against regular Federal income tax liability. Accordingly, the Company utilized on its tax returns $27.5 million of Section 29 tax credits in 1994 and anticipates the utilization of $15.6 million in 1996. Section 29 tax credits of $18.8 million in 1995 increased the alternative minimum tax credit and may be carried over and applied against regular tax liability in future years.
All tax years prior to 1979 have been closed with the Internal Revenue Service ("IRS"). UPC has reached a partial settlement with the Appeals Office of the IRS for 1980 through 1985; the remaining issues will be resolved as part of refund claims filed for those years. Additionally, UPC is negotiating with the Appeals Office concerning 1986 through 1989. The IRS is examining UPC's returns for 1990 through 1994. The Company believes it has adequately provided for Federal and state income taxes.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. DEBT
Total debt as of December 31 is summarized below:
Excluding commercial paper, the Company has no debt maturing in the next five years. Outstanding commercial paper has been classified as long-term debt reflecting the Company's intent to maintain these short-term borrowings on a long-term basis either through the continued issuance of commercial paper and/or through new long-term financings, or by using its currently available long-term credit facility if alternative financing is not available.
The Company has a $600 million revolving credit agreement that expires in August 2001. Borrowings under the agreement, at the Company's election, bear interest either at a spread over London Interbank Offered Rate ("LIBOR") or at a spread over domestic certificate of deposit rates, in each case depending on the Company's senior debt rating. The Company is required to pay facility fees on the aggregate amount of the commitment ranging from .06% to .15% also depending on the Company's senior debt rating. The agreement contains covenants which limit the ratio of debt to the sum of debt and shareholders' equity of the Company to 65% and which require the combined EBITDAX (the sum of operating income; depreciation, depletion and amortization; and exploration expenses) of the Company's Principal Operating Subsidiaries (as defined in the agreement) to be at least 80% of the Company's consolidated EBITDAX. The agreement also imposes certain restrictions on the Company regarding the creation of liens, incurrence of indebtedness, transactions with affiliates, sales of the stock of UPRC and certain mergers, consolidations and asset sales. As of December 31, 1996, there were no borrowings outstanding under this credit facility although borrowing capacity is reduced by outstanding commercial paper. The Company had the capacity to borrow $500 million under such credit facility as of December 31, 1996.
In October 1996, the Company issued $200 million of 7% Notes due 2006 and $200 million of 7.5% Debentures due 2026. In November 1996, the Company issued $150 million of 7.5% Debentures due 2096. Proceeds were used, together with proceeds from the issuance of commercial paper, to repay the Company's note payable to UPC and for general corporate purposes. None of the Company's Notes and Debentures are redeemable prior to maturity and none are subject to any sinking fund requirements. In addition, the Company has filed a Form S-3 Registration Statement with the Securities and Exchange Commission which would permit the Company to offer up to $900 million in debt and equity securities upon the effectiveness of such Registration Statement.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. LEASES
The Company leases its headquarters office building, certain production platforms and other property. Future minimum lease payments for operating leases with initial non-cancelable lease terms in excess of one year as of December 31, 1996, are as follows:
Rent expense, net of sublease income, for operating leases with terms exceeding one month was $33.8 million in 1994, $31.0 million in 1995 and $27.2 million in 1996. Sublease rentals for the next five years are $28.7 million in 1997, $28.4 million in 1998, $28.3 million in 1999, $28.1 million in 2000, $28.1 million in 2001 and $56.7 million thereafter.
10. RETIREMENT PLANS
The Company provides pension, health care and life insurance benefits to all eligible retirees.
Pension Benefits. Pension plan benefits are based on years of service and compensation during the last years of employment. Contributions to the plans are calculated based on the Projected Unit Credit actuarial funding method and are not less than the minimum funding standards set forth in the Employee Retirement Income Security Act of 1974, as amended. The following pension credits and funded status are based on historical actuarial valuations.
Pension cost includes the following components:
The projected benefit obligation was determined using a discount rate of 7.25% in 1995 and 7.5% in 1996. The estimated rate of salary increase approximated 5.25% in 1995 and 5.5% in 1996. The expected long-term rate of return on plan assets was 8.0% in both years. The portion of the funded plan's assets held in fixed-income and short-term securities was approximately 32% and 29% as of December 31, 1995 and 1996, respectively, with the remainder primarily in equity securities.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The funded status of the plans as of December 31 is as follows:
In connection with the Distribution, pension assets related to UPC's funded pension plan, in which the Company had participated, were allocated between UPC and the Company, resulting in the elimination of the balance of net pension assets and the creation of a December 31, 1996 funded pension liability of $76.2 million, as well as a net-of-tax charge to retained earnings of $69.5 million. The Company has adopted a new pension plan with substantially the same terms as those of the UPC pension plan. The additional cost to the Company associated with the allocation of pension assets between UPC and the Company is expected to be approximately $8 million annually.
Other Postretirement Benefits. Postretirement health and life insurance benefits cost includes the following components:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The liability for other postretirement benefit plans as of December 31 is as follows:
The APBO was determined using a discount rate of 7.25% in 1995 and 7.5% in 1996. The health care cost trend rate is assumed to gradually decrease from 9.5% for 1997 to 5.0% for 2009 and all future years. If the assumed health care cost trend rate increases by one percentage point in each subsequent year, the aggregate of the service and interest cost components of annual postretirement benefit expense would increase by $0.6 million and the APBO would rise by $4.4 million. The Company does not currently pre-fund health care and life insurance benefit costs. Cash payments for these benefits were $1.6 million in 1995 and $3.6 million in 1996.
11. SHAREHOLDERS' EQUITY
Stock Option and Retention Stock Plans. Pursuant to the Company's stock option and retention stock plans, 11,660,601 and 9,215,933 shares of common stock or options for such shares were available at December 31, 1995 and 1996, respectively, for grant to employees and directors. Options under the plans are granted at 100% of fair market value at the date of grant, become exercisable no earlier than one year after grant and are exercisable for a period of up to ten years from grant date. Multi-year option grants have been made to officers and key employees and vest over a three-year period from grant date.
Retention shares of common stock are awarded under the plans to eligible employees, subject to forfeiture if employment terminates during the prescribed retention period, generally one to five years from grant. Multi-year retention stock awards also have been made, with vesting three to five years from grant.
To become exercisable, 1994 multi-year grants of stock options and retention stock also required that designated Company stock prices be met. These performance conditions were achieved during 1995 for stock options and during 1996 for retention stock.
Upon completion of the Offering and Distribution, UPC non-qualified stock options and certain UPC Incentive Stock Options ("ISOs"), as well as UPC retention shares held by officers and employees of the Company, were converted into non-qualified Company stock options, ISOs and retention shares, respectively. The converted options and retention shares retain the same exercise dates and vesting requirements as the UPC options and retention shares for which they were exchanged.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The status of the Company's stock-based compensation programs is as follows:
Weighted-average grant-date fair value of options and retention shares granted:
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(a) Activity occurred prior to achievement of performance conditions.
(b) Calculated in accordance with the Black-Scholes option pricing model, using the following assumptions:
(c) Represents market value on grant date.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Stock options outstanding as of December 31, 1996 are as follows:
The Company applies the intrinsic value method in accounting for its stock option and retention stock plans. Accordingly, no compensation cost has been recognized for its stock option plans. Compensation cost recognized for its retention stock plan was $0.7 million and $7.4 million in 1995 and 1996, respectively. Had compensation cost for the Company's stock option plan been determined based on the fair value at the grant dates for awards under the plan and for options that were converted at the Offering and Distribution, as described above, the Company's net income would have been reduced by $3.4 million in 1995 (essentially all of which relates to option conversion at the Offering) and $3.0 million in 1996 (of which $0.7 million relates to option conversion at the Distribution). Earnings per share would have been reduced by $0.01 per share in both 1995 and 1996.
Employee Stock Ownership Plan. Effective January 2, 1997, the Company instituted an employee stock ownership plan ("ESOP"). The ESOP purchased 3.7 million shares or $107.3 million of newly issued common stock (the "ESOP Shares") from the Company, which will be used to fund the Company's matching obligation under its 401(k) Thrift Plan. All regular employees of the Company are eligible to participate in the ESOP.
The ESOP Shares, which are held in trust, were purchased with the proceeds from a 30-year loan from the Company. Such shares initially have been pledged as collateral for the loan. As loan payments are made, shares will be released from collateral, based on the proportion of debt service paid. Principal and interest requirements are $8.7 million annually, and will be funded with dividends paid on the unallocated ESOP Shares and with cash contributions from the Company. Principal or interest prepayments may be made to ensure that the Company's minimum matching obligation is met.
Shares held by the ESOP will be included in the computation of earnings per share as such ESOP Shares are released from collateral. Such releases of ESOP Shares will be allocated to participants' accounts and will be charged to compensation expense at the fair market value of the shares on the date of the employer match. Dividends on allocated ESOP Shares will be recorded as a reduction of retained earnings; dividends on unallocated ESOP Shares will be recorded as a reduction of the principal or accrued interest on the loan.
Preferred Stock and Shareholder Rights. The Company has 100 million shares of no-par-value preferred stock authorized, none of which are outstanding. On October 28, 1996, the Company's Board of Directors designated 3,000,000 of the authorized preferred shares as non-redeemable Series A Junior Participating Preferred Shares (the "Series A Preferred Stock"). Upon issuance, each one-hundredth of a share of the Series A Preferred Stock will have dividend and voting rights approximately equal to those of one share of the Company's common stock. In addition, on October 28, 1996, the Board of Directors adopted a shareholder rights plan with a "flip-in" threshold of 15% to ensure that all shareholders of the Company receive fair value for their common stock in the event of any proposed takeover of the Company and to guard against the use of coercive tactics to gain control of the Company without offering fair value to the Company's shareholders. Under the related Rights Agreement, the Company declared a dividend of one right ("Right") for each outstanding share of common stock to shareholders of record on November 7, 1996. Under certain limited
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
conditions as defined in the Rights Agreement, each Right entitles the registered holder to purchase from the Company one one-hundredth of a share of Series A Preferred Stock at $135 subject to adjustment. The Rights are not exercisable until the Distribution Date (as defined in the Rights Agreement) which will occur upon the earlier of (i) ten days following a public announcement that an Acquiring Person (as defined in the Rights Agreement) has acquired beneficial ownership of 15% or more of the Company's outstanding common stock (the "Stock Acquisition Date") or (ii) ten business days following the commencement of a tender offer or exchange offer that would result in a person or group owning 15% or more of the Company's outstanding common stock.
The Rights have certain anti-takeover effects. The Rights will cause substantial dilution to a person or group that attempts to acquire the Company without conditioning the offer on a substantial number of Rights being redeemed. In the event that at any time following the Stock Acquisition Date certain events occur as defined in the Rights Agreement, each holder of a Right, except the Acquiring Person, will thereafter have the right to receive, upon exercise, Company common stock or common stock of the acquiring company, as the case may be, having a value equal to two times the exercise price of the Right.
The Rights should not interfere with any merger or other business combination approved by the Company since the Board of Directors may, at its option, at any time prior to the close of business on the earlier of the tenth day following the Stock Acquisition Date or October 28, 2006, redeem all but not less than all of the then outstanding Rights at $0.01 per Right. The Rights expire on October 28, 2006, and do not have voting power or dividend privileges.
12. INVESTMENT IN UNCONSOLIDATED AFFILIATE
The Company has a 50% ownership interest in Black Butte Coal Company and R-K Leasing Company ("Black Butte"), a partnership which operates a surface coal mine complex in southwestern Wyoming. Summarized financial information for Black Butte as of and for the year ended December 31 is as follows:
During 1996, Black Butte's sales to its largest customer under an amended coal supply contract accounted for $54.8 million, or 10%, of the Company's consolidated operating income. Operating income from this amended contract is expected to be relatively constant through the end of 2001, when the financially beneficial terms of this agreement will terminate. Although Black Butte continues to seek new buyers for its low-sulfur coal, its mining costs are considerably higher than the mining costs for competing supplies. The Company does not expect to be able to replace the operating income it currently receives under the amended contract with incremental coal sales.
A supplier of coal to Black Butte has been assessed by the Minerals Management Service of the United States Department of the Interior and the State of Montana Department of Revenue for underpayment of royalties and production taxes related to coal previously sold to Black Butte. The supplier is contesting these claims; however, should the claims be successful the supplier may make a claim for reimbursement from Black Butte. Although the management of Black Butte will vigorously contest these claims, the liability
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associated with the underpaid royalty and production taxes, if any, could range from zero to $36 million, of which the Company would recognize its proportionate share, which could range from zero to $18 million.
13. ENVIRONMENTAL EXPOSURE
The Company generates and disposes of hazardous and nonhazardous waste in its current and former operations and is subject to increasingly stringent Federal, state and local environmental regulations. The Company has identified 10 sites currently subject to environmental response actions or on the Superfund National Priorities List or state superfund lists, at which it is or may be liable for remediation costs associated with alleged contamination or for violations of environmental requirements. Certain Federal legislation imposes joint and several liability for the remediation of various sites; consequently, the Company's ultimate environmental liability may include costs relating to other parties in addition to costs relating to its own activities at each site. In addition, the Company is or may be liable for certain environmental remediation matters involving existing or former facilities.
As of December 31, 1996, long and short-term liabilities totaling $94.3 million had been accrued for future costs of all sites where the Company's obligation is probable and where such costs reasonably can be estimated; however, the ultimate cost could be lower or as much as 10% higher. This accrual includes future costs for remediation and restoration of sites, as well as for ongoing monitoring costs, but excludes any anticipated recoveries from third parties. The accrual also includes $44.2 million for the obligation to participate in the remediation of the Wilmington field properties (see Note 4). Cost estimates were based on information available for each site, financial viability of other Potentially Responsible Parties ("PRPs") and existing technology, laws and regulations. The Company believes that it has accrued adequately for its share of costs at sites subject to joint and several liability. The ultimate liability for remediation is difficult to determine with certainty because of the number of PRPs involved, site-specific cost sharing arrangements with other PRPs, the degree of contamination by various wastes, the scarcity and quality of volumetric data related to many of the sites and the speculative nature of remediation costs.
The Company also is involved in reducing emissions, spills and migration of hazardous materials. Remediation of identified sites and control and prevention of environmental exposures required spending of $6.2 million in 1995 and $11.4 million in 1996. In 1997, the Company anticipates spending a total of $20 million for remediation, control and prevention, including $10 million relating to the Wilmington properties. The majority of the December 31, 1996 accrued environmental liability is expected to be paid out over the next five years, funded by cash generated from operations. Based on current rules and regulations, management does not expect future environmental obligations to have a material impact on the results of operations or financial condition of the Company.
In addition, Black Butte provides an accrual for reclamation of mined properties, based on the estimated cost of restoration of such properties in compliance with laws governing strip mining. Accrued reclamation costs for Black Butte as of December 31, 1996 are $54.3 million, of which the Company's share is $27.2 million. The majority of cash expenditures for reclamation are expected to be incurred from five to ten years in the future.
14. COMMITMENTS AND CONTINGENCIES
UP Fuels is a party to a long-term firm transportation agreement with Kern River Gas Transmission Company that expires in 2007. Under the transportation agreement, UP Fuels has the right to transport 75 MMcfd of gas on the Kern River Pipeline system which extends from Opal, Wyoming, to an interconnection with the Southern California Gas Company pipeline system in southern California. Eleven years remain on the primary term of the agreement, and the current transportation rate is $0.69 per Mcf. UP Fuels is obligated to pay the fixed portion of that rate, presently $0.6878 per Mcf, whether or not it actually transports any gas. This rate will be in effect through at least mid-1997, and thereafter can change based on
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
cost of service factors and prevailing rate policy at the Federal Energy Regulatory Commission. The undiscounted amount of the commitment is $197 million. UP Fuels is party to an additional agreement under which it may acquire in 2001, at its option, an additional 25 MMcfd of transportation rights on the Kern River system for periods beginning in 2002.
In the last ten years, the Company has disposed of significant pipeline, refining and producing property assets, including the sale of its 37.5% interest in a Corpus Christi petrochemical complex (July 1987), the Calnev pipeline (October 1988), the Wilmington refinery (December 1988), the Corpus Christi refinery (half sold in March 1987 and the balance in January 1989), and Wilmington field (March 1994). In connection therewith, the Company has given certain representations and warranties relating to the assets sold (covering, among other matters, the condition and capabilities of assets and compliance with environmental and other laws) and certain indemnities with respect to liabilities associated with such assets. With respect to the Calnev pipeline and the Corpus Christi and Wilmington refinery sales, the Company has been advised of possible claims which may be asserted by the relevant purchasers for alleged breaches of representations and warranties. Certain claims related to compliance with environmental laws remain pending. In addition, as some of the representations, warranties, and indemnities related to some of the disposed assets have not expired, further claims may be made against the Company. While no assurance can be given as to the actual outcome of these claims, the Company does not expect these matters to have a materially adverse effect on its results of operations or financial condition.
There are lawsuits pending against the Company and certain of its subsidiaries which are described in Part I, Item 3 -- "Legal Proceedings" in this report. The Company intends to defend vigorously against these lawsuits as well as any similar lawsuits. If such suits ultimately are resolved against the Company on a widespread basis, however, damage awards and a loss of future revenue could result which, in the aggregate, could be materially adverse to the Company.
The Company is a defendant in a number of other lawsuits and is involved in governmental proceedings arising in the ordinary course of business in addition to those described above. The Company also has entered into commitments and provided guarantees for specific financial and contractual obligations of its subsidiaries and affiliates. The Company does not expect that these lawsuits, commitments or guarantees will have a materially adverse effect on its results of operations or financial condition.
15. OTHER LONG-TERM LIABILITIES
Other long-term liabilities as of December 31 include the following:
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16. CAPITAL AND EXPLORATORY EXPENDITURES
Capital and exploratory expenditures include the following:
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SUPPLEMENTARY INFORMATION (UNAUDITED)
A. PROVED RESERVES
The following table reflects estimated quantities of proved oil and gas reserves which have been prepared by the Company's petroleum engineers. The Company considers such estimates to be reasonable; however, there are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company. Reserve engineering is a subjective process which is dependent on the quality of available data and on engineering and geological interpretation and judgment. Such reserve estimates are subject to change over time as additional information becomes available.
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(a) Includes the plant share of equity gas processed (natural gas and natural gas liquids, as appropriate, earned by gas processing facilities through the processing of the Company's equity production).
(b) Calculated using the ratio of one Bbl to six Mcf.
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SUPPLEMENTARY INFORMATION (UNAUDITED) -- (CONTINUED)
B. DRILLING ACTIVITY(A)
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(a) In addition, at December 31, 1996, 140 gross wells (95 net wells) were in the process of being drilled.
C. AVERAGE SALES PRICE AND COST
D. AVERAGE DAILY PRODUCTION AND SALES VOLUME
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SUPPLEMENTARY INFORMATION (UNAUDITED) -- (CONTINUED)
E. ACREAGE AND WELLS
Oil and gas leasehold acreage as of December 31 is as follows(a):
Productive oil and gas wells at December 31, 1996 are as follows:
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(a) In addition, the Company has fee mineral ownership of approximately 9.6 million gross acres (8.5 million net acres), including 7.9 million gross acres (7.7 million net acres) acquired through 19th century Congressional Land Grant Acts. Substantial portions of this acreage are undeveloped and are considered prospective for oil and gas.
(b) Approximately 577 are multiple completions, 405 of which are gas wells.
F. CAPITALIZED EXPLORATION AND PRODUCTION COSTS
Capitalized exploration and production costs as of December 31 are as follows(a):
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(a) Excludes plants, pipelines and marketing assets.
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SUPPLEMENTARY INFORMATION (UNAUDITED) -- (CONTINUED)
G. COSTS INCURRED IN EXPLORATION AND DEVELOPMENT
Costs incurred (whether capitalized or expensed) in oil and gas property acquisition, exploration and development activities are as follows:
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(a) Includes allocated exploration overhead costs of $21.6 million in 1994, $17.1 million in 1995 and $22.5 million in 1996, and delay rentals of $4.6 million in 1994, $3.6 million in 1995 and $4.4 million in 1996.
(b) Excludes capital expenditures relating to plants, pipelines and marketing of $329.8 million in 1994, $106.5 million in 1995 and $118.1 million in 1996.
H. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES(A)
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(a) Plants, pipelines and marketing results, general and administrative expenses and interest costs have been excluded in computing these results of operations. Revenues include net gains from sales of assets of $26.5 million in 1994, $14.2 million in 1995 and $3.9 million in 1996, and the $122.5 million Columbia bankruptcy settlement in 1995.
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SUPPLEMENTARY INFORMATION (UNAUDITED) -- (CONTINUED)
I. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
An analysis of changes in the standardized measure of discounted future net cash flows follows:
Future oil and gas sales and production and development costs have been estimated using prices and costs in effect as of each year end. Prices used to estimate future oil and gas sales represent the closing price for trading in December contracts on the New York Mercantile Exchange adjusted for appropriate regional price differentials. Future production hedged as of year end is included in future net revenues at the hedged price. Such prices may vary significantly from actual prices realized by the Company for its future production. Future net revenues were discounted to present value at 10%, a uniform rate set by the Financial Accounting Standards Board. Income taxes represent the tax effect (at statutory rates) of the difference between the standardized measure values and tax bases of the underlying properties at the end of the year.
Changes in the supply and demand for oil, natural gas and natural gas liquids, hydrocarbon price volatility, inflation, timing of production, reserve revisions and other factors make these estimates inherently imprecise and subject to substantial revision. As a result, these measures are not the Company's estimate of future cash flows nor do these measures serve as an estimate of current market value.
UNION PACIFIC RESOURCES GROUP INC.
SUPPLEMENTARY INFORMATION (UNAUDITED) -- (CONTINUED)
J. SELECTED QUARTERLY DATA
Selected unaudited quarterly data are as follows:
- - --------------- (a) Fourth quarter 1996 results reflect the impact of increases in hydrocarbon prices (see "Management's Discussion and Analysis of Financial Condition and Results of Operations"). In addition, during the fourth quarter of 1996, operating revenues reflect the release of a $31.3 million contingency accrual related to potential claims in connection with the 1995 Columbia bankruptcy settlement (see Note 4) and operating expenses were impacted by $43.5 million related to the writeoff and impairment of certain oil and gas assets (see Note 6).
(b) In November 1995, the Company recorded a $122.5 million pre-tax ($78.5 million after-tax) gain resulting from the Columbia bankruptcy settlement (see Note 4).
(c) Net income and dividends per share have been omitted for all periods prior to the fourth quarter of 1995 as the Company was a wholly owned subsidiary of UPC until October 1995 (see Note 2).
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Directors of Registrant.
Information as to the names, ages, positions and offices with the Company, terms of office, periods of service, business experience during the past five years and certain other directorships held by each director or person nominated to become a director is set forth in the Election of Directors segment of the Proxy Statement and is incorporated herein by reference.
(b) Executive Officers of Registrant.
Information concerning executive officers is presented in Part I of this report under Executive Officers of the Registrant.
(c) Section 16(a) Compliance.
Information concerning compliance with Section 16(a) of the Securities Exchange Act of 1934 is set forth in the Reports of Ownership segment of the Proxy Statement and is incorporated herein by reference.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
Information concerning remuneration received by executive officers and directors is presented in the Compensation of Directors, Compensation Committee Interlocks and Insider Participation and Executive Compensation segments of the Proxy Statement and is incorporated herein by reference.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information as to the number of shares of equity securities beneficially owned as of March 3, 1997, by each director and nominee for director, the five most highly compensated executive officers and directors and executive officers as a group is set forth in the Security Ownership of Certain Executive and Beneficial Owners segment of the Proxy Statement and is incorporated herein by reference.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information on related transactions is set forth in the Compensation Committee Interlocks and Insider Participation segment of the Proxy Statement and is incorporated herein by reference.
PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) and (2) Financial Statements and Schedules.
See "Index to Consolidated Financial Statements" set forth on page 30.
No schedules are required to be filed because of the absence of conditions under which they would be required or because the required information is set forth in the financial statements referred to above.
(a)(3) Exhibits.
Exhibits not incorporated herein by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to the Company's Form S-1 Registration Statement, Registration No. 33-95398, filed on October 10, 1995 ("Form S-1") or as otherwise indicated.
(b) Reports on Form 8-K.
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 21st day of March, 1997.
UNION PACIFIC RESOURCES GROUP INC.
By /s/ MORRIS B. SMITH ----------------------------------- (Morris B. Smith, Vice President and Chief Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below, on this 21st day of March, 1997, by the following persons on behalf of the registrant and in the capacities indicated.
INDEX TO EXHIBITS
- - ---------------
* Filed herewith