ITEM 1. BUSINESS
GENERAL
Union Pacific Resources Group Inc. (a Utah corporation) and subsidiaries (collectively, the "Company" or "UPR") is engaged primarily in the exploration for and the development and production of natural gas, natural gas liquids ("NGLs") and crude oil in several major producing basins in the United States, Canada, Guatemala, Venezuela and other international areas. In addition, the Company engages in the hard minerals business through non-operated joint venture and royalty arrangements in several coal, industrial minerals and trona (natural soda ash) mines located on lands within and adjacent to its Land Grant holdings in Wyoming. The Land Grant consists of land that passes through the states of Colorado and Wyoming and into Utah, which was granted by the Federal government to a predecessor of the Company in the mid-1800s. In the Land Grant, the Company has fee ownership of the mineral rights under approximately 7.9 million acres. As of December 31, 1999, over 68 percent of the revenues, 44 percent of the fixed assets and 56 percent of the proved reserves of the Company are generated or located in the United States. As of December 31, 1999, 19 percent of the revenues, 35 percent of fixed assets and 28 percent of the proved reserves of the Company are generated or located in Canada.
In March 1998, the Company acquired Norcen Energy Resources Limited ("Norcen") for a cash purchase price of $2.634 billion ("Norcen Acquisition"). The Company also assumed long-term debt obligations of Norcen totaling approximately $1 billion and funded the purchase price through the issuance of commercial paper, supported by a U.S. $2.7 billion 364-Day Competitive Advance/Revolving Credit Agreement dated March 2, 1998. Norcen was a major Canadian oil and gas exploration and production company with primary operations in western Canada, the Gulf of Mexico, Guatemala and Venezuela. The acquisition expanded the Company's operations beyond its historical domestic focus. See Note 2 to the Consolidated Financial Statements.
Following the Norcen Acquisition, the Company commenced a deleveraging program which included the sales in 1998 and 1999 of approximately $745 million of non-strategic properties. Additionally, the Company sold its gathering, processing and marketing ("GPM") business segment to Duke Energy Field Services, Inc. ("Duke") for $1.36 billion in March 1999 ("GPM Disposition"). See "Deleveraging Program and Discontinued Operations" in Note 3 to the Consolidated Financial Statements.
BUSINESS STRATEGY
During 1999, the Company shifted its business strategy from prior years. The Company sold its GPM business segment and began to focus on its upstream exploration and production business segment. Although other international operations, primarily in Latin America, were expanded as a result of the Norcen Acquisition, the Company focuses primarily on onshore North American core operating areas where it has expertise and a large acreage position with natural gas prospects and can create shareholder value.
The Company's strategy is to become the premier North American onshore exploration and production value creator through its technical and operational abilities in the exploitation of natural gas, primarily in Texas, the Rockies and Canada. In each of its core areas, the Company focuses on the exploration for and the development of natural gas and crude oil resources, in combination with efforts to increase margins through reductions in drilling and operating costs. The Company's long-term strategy is to increase production by enhancing well results through the application of economies of scale, its operating experience in its core geographic areas and its expertise in advanced drilling and completion technologies. The Company strives to keep its drilling inventory high to supply its drilling operations with an inventory of drill sites in its core areas through development of its existing properties, exploration, farm-in agreements and acquisitions of properties and companies. The Company maintains a high working interest in its core areas and typically serves as operator, which allows it to control the timing and cost of exploration and development activities and to enhance its ability to apply its expertise to these properties.
The Company plans to increase its capital spending in 2000 from the $428 million spent in 1999 to approximately $650 million for exploration and development projects. The Company plans an additional $100 million for select property acquisitions. The capital program will be funded through cash provided by operations. Almost 83 percent of the capital budget will be focused on the development of fields which have already been proved and which are expected to provide more immediate cash flow with low risk. The remainder of the Company's budget will be for select exploration projects and other development drilling that has the potential for long-term impact. Both the development and exploration programs will employ the Company's ongoing strategy of applying its expertise in advanced drilling and completion technologies. Approximately 38 percent of the capital budget will be invested in U.S. Onshore, 29 percent in Canada, 14 percent in U.S. Offshore and 19 percent in Other International. The Company may adjust its capital spending as commodity prices and cash flows change. The extent and timing of capital spending may also be affected by changes in business, financial and operating conditions as well as by the timing and availability of suitable investment opportunities. See "Outlook and Other Matters."
The Company's primary financial strategy is to continue to improve its balance sheet by reducing debt. During 1999, the Company reduced total debt by over 39% or approximately $1.8 billion. During 2000, the Company expects to further reduce debt by at least $200 million. The Company expects its cash provided by operations to be approximately $1 billion for 2000, assuming a NYMEX price forecast of $26 per barrel for crude oil and $2.70 per Mcf for natural gas. To the extent that cash provided by operations is generated in excess of this forecast or due to the monetization of assets, the additional cash could be used to further reduce debt and/or initiate a common stock repurchase program if approved by the Board of Directors. See "Outlook and Other Matters."
EXPLORATION AND PRODUCTION OPERATIONS
The Company's exploration and production operations are organized into four primary business operating areas: U.S. Onshore, U.S. Offshore, Canada and Other International. Other International is comprised of Guatemala, Venezuela and other international operations.
The following table sets forth 1999 capital spending, production information and proved reserves as of December 31, 1999, with respect to each of the Company's operating areas. Natural gas constituted 58% of the Company's total proved reserves of 5.7 Tcfe as of December 31, 1999, and 59% of the Company's sales volumes of 2.15 Bcfed for the year then ended. Production from properties sold in 1999 is included in producing property volumes for each area through the date of each sale.
United States Operations
The Company's United States operations currently has proved reserves of 3.2 Tcfe and produced 1,413 MMcfed in 1999. Over 70 percent of the proved reserves in the United States is natural gas. Capital spending in the United States in 1999 was $238 million.
U.S. Onshore
The Company's U.S. Onshore oil and gas activities are concentrated in five core geographic areas. The core areas in the U.S. Onshore are comprised of the following: (1) the Land Grant area in Colorado, Wyoming and Utah, (2) the Coastal Plain area of Texas and Louisiana, (3) the Austin Chalk trend in Texas and Louisiana, (4) the East Texas area and (5) the West Texas area. During 1999, the Company spent $185 million or 43 percent of its capital budget in the U.S. Onshore and produced 1,274 MMcfed or 59 percent of the Company's total produced volumes.
The Land Grant core area includes the Company's oil and gas properties in Colorado, Wyoming and Utah, and the Hugoton/Panoma field in Kansas. The Company's operations in the Land Grant are concentrated in the Green River Basin and the Overthrust area. The Company currently controls approximately 8.9 million developed and undeveloped net acres, principally attributable to its Land Grant ownership. During 1999, the Company drilled a successful Rock Island 4H well in the deep over-pressured Frontier formation of the Green River Basin. Although the wells drilled in early 2000 near the Rock Island 4H were not successful, the formation's resource is large so the Company will continue to test the Frontier formation during 2000 to further understand its potential.
The Coastal Plain core area includes the Company's oil and gas properties along the onshore coastal plain of Texas and Louisiana. In addition to its producing activities, the Company conducted extensive seismic evaluations in 1999 and drilled a successful exploration well in the Company's Etouffee prospect in South Louisiana. The Company will continue to develop this area and explore the nearby Turtle Soup area during 2000, while bringing on production from the successful well in the Etouffee prospect.
The Austin Chalk core area includes the Company's oil and gas properties 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 three fields: Giddings, Brookeland and Masters Creek. The Company controls nearly 1.9 million developed and undeveloped net acres in the Austin Chalk.
The East Texas core area includes the Company's oil and gas properties in northeastern Texas, primarily in the Carthage and Oakhill fields. In addition to its Carthage and Oakhill production operations, the Company has participated in 3-D seismic and has identified several high impact exploratory prospects.
The West Texas core area includes the Company's oil and gas properties in western Texas, primarily in the Ozona field. The Company has drilled approximately 1,000 wells in the Ozona area, which is characterized by long-lived natural gas wells that typically produce for 30 or more years.
U.S. Offshore
The U.S. Offshore operations are comprised of the Company's oil and gas properties in the Gulf of Mexico, including operations added in the Norcen Acquisition in 1998. During 1999, the Company spent $53 million of its capital budget in the U.S. Offshore and produced 139 MMcfed. During 1997, the Company drilled a successful deepwater well in Mississippi Canyon Block 755 in the Gulf of Mexico, which resulted in the discovery of significant reserves. The Company has and will continue to delineate the discovery during 2000 and 2001, with first production anticipated in 2002. The Company may also drill an exploration well in both the Garden Banks Block 700 and Green Canyon Block 281 during 2000.
Canadian Operations
The Company's Canadian operations principally include properties acquired in the Norcen Acquisition. Operations in ten core areas are centered in the province of Alberta, with additional properties in northeastern British Columbia and southwestern Saskatchewan. Canada currently has proved reserves of 1.6 Tcfe and produced 462 MMcfed in 1999. Capital spending in 1999 in Canada was $123 million. Canada provides a balanced commodity mix of 35 percent crude oil and NGLs and 65 percent natural gas, as well as an asset portfolio with long reserve lives. Approximately 46 percent of Canadian oil production is heavy oil. The Company has significant heavy crude oil assets in the Moose Hill, Lindbergh and Hayter areas which are located in eastern Alberta and western Saskatchewan. These areas cover approximately 420,000 acres and consist of over 860 producing wells and over 1,000 drill site prospects. As a result of the Company's successful Klua well in British Columbia during 1999, the Company will continue to focus on the region and add reserves.
Other International Operations
The Company's Other International oil and gas operation activities are concentrated in Latin America, primarily in Guatemala and Venezuela. The Company also maintains less significant international oil and gas operation activities, including interests in six fields in Argentina, two non-operated offshore producing properties in Australia, an exploitation interest in Brazil with potential exploration upside, and a producing interest in a non-operated property in Egypt. Other International currently has proved reserves of 0.9 Tcfe and produced 277 MMcfed in 1999.
Guatemala. The Company's Guatemalan operations are conducted by Basic Resources International, a company that was acquired in the Norcen Acquisition. The majority of activity for the Guatemalan operations is currently in the Xan area, producing heavy to medium quality crude oil. The Company owns a 100 percent working interest in several exploration blocks and is focusing on an aggressive seismic acquisition strategy to evaluate exploration and development opportunities. Capital spending in 1999 in Guatemala was $19 million, with average production volumes of 21 MBbld. The Company owns, controls and operates infrastructure in Guatemala which includes gathering and processing facilities at each producing field, an asphalt refinery, 285 miles of pipeline with seven pump stations and a 420 MBbl capacity shipping terminal on the Caribbean coast. The combination of these assets provides the Company with an integrated network of facilities from producing fields to the port.
Venezuela. The Company's Venezuelan operations primarily consist of the Oritupano-Leona and the West Guarico concessions. The Oritupano-Leona block, in which the Company has a 45 percent working interest, covers 433,000 acres and has approximately 205 producing wells. Most of the activity in the block has been driven by a 3-D seismic program conducted in prior years. The West Guarico block covers over 800,000 acres, approximately nine producing wells and is operated by the Company, which has a 50 percent working interest. The project is in the beginning stages of redevelopment and in 1999, the Company focused on seismic, drilling, recompletions and the improvement of infrastructure. After drilling a dry hole on the Delta Centro prospect in 1999, the Company fully impaired the project's lease with a $50 million charge to exploration expense. During 1999, the Company spent $43 million of capital in Venezuela, with average production volumes of 19 MBbld.
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the Company's volumes and average price realizations after the effects of hedging for natural gas, NGL and crude oil sales, and average production costs per Mcfe for each of the last three years.
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(a) Includes lease operating costs, production overhead, other operating expenses and taxes other than income taxes.
PRINCIPLE CUSTOMER
In connection with the GPM Disposition, the Company entered into a long-term sales agreement with Duke. The long-term sales agreement obligates the Company to sell the majority of its domestic natural gas and existing NGL production to Duke through March 2004. During 1999, sales to Duke accounted for 31% of the Company's consolidated revenues and 38% of United States revenues.
MINERALS
The Minerals business segment 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 non-operated joint venture and royalty arrangements in coal, trona and industrial mineral mines. In general, the Company reinvests the cash flow from its hard minerals operations into its oil and gas business segment. The Minerals business segment generated $117.8 million of operating income during 1999, as follows:
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(a) Includes royalties from properties leased to four soda ash producers. In total, these properties contain resources sufficient to support over 50 years of production at current production levels.
(b) The Company leases coal resources to six operating mines. In 1999, 52 percent 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.
(c) Represents operating income from the Company's 49 percent interest in OCI Wyoming LP, a non-operated joint venture.
(d) Represents operating income from the Company's 50 percent non-operating interest in Black Butte Coal Company ("Black Butte").
The Company's low sulfur coal deposits, which are located in southeastern Montana and southwestern Wyoming, compete with other western coal for industrial and utility boiler markets which burn the coal to produce steam to generate electricity. The Company's mines primarily use the surface mining method of extraction, although the Company also receives royalties on some underground mines. The Company's coal mines are served by a single rail line and incur greater transportation costs than some of its competitors in the western United States. Additionally, competing western coal companies in the Powder River Basin in Wyoming have lower stripping ratios than the Company's mines. At current coal pricing and higher transportation and extraction cost levels, 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.
Approximately 80%, 84% and 78% of the Black Butte revenues in 1999, 1998 and 1997, respectively were derived from a coal supply contract with Commonwealth Edison Company which terminates at the end of 2000. In 1999, $73.4 million of the Company's operating income was attributable to the contract. See "Management's Discussion and Analysis of Financial Condition Results of Operations", "Outlook and Other Matters" and Note 14 to the Consolidated Financial Statements.
The world's largest deposit of trona, constituting 90 percent of the world's known trona resources, is located in the Green River Basin in southwestern Wyoming. All of the reserves which can be mined in this trona deposit lie within the Land Grant and adjoining lands. The Company owns lands containing approximately 50% of these reserves and has leased a portion of those lands to companies which mine and refine trona. 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 contributes 31 percent of the world soda ash supply with the remainder principally from synthetic processes. In addition to fee mineral ownership of and royalty interests in trona reserves, the Company, along with its partner, Oriental Chemical Industries, Inc. ("OCI"), owns a soda ash refining facility at OCI Wyoming LP. This facility is ranked second in soda ash capacity among domestic producers at 3.1 million tons per year.
COMPETITION
The oil and gas industry is highly competitive. The Company actively competes for reserve acquisitions, exploration leases, licenses, 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. In the past several years, some consolidation within the industry has occurred, as companies combined their strengths and financial resources to improve overall stability and operating efficiencies and to reduce costs. 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, pipeline access and types and quality of service.
GOVERNMENT REGULATION
The Company's natural gas, NGL and crude oil exploration, development and production operations are subject to extensive rules and regulations promulgated by Federal, provincial, state and local authorities and foreign governmental entities.
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 non-compliance. 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 the U.S. Department of the Interior, Minerals Management Service ("MMS"). Such leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed MMS regulations and orders. Certain operations on such leases must be conducted pursuant to appropriate permits issued by 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. In 1998, the MMS adopted financial responsibility regulations under the Oil Pollution Act of 1990. See "Environmental Regulation -- Oil Spills."
Currently, there are no Federal, state or local laws that regulate the price for sales of natural gas, NGLs or crude oil produced by the Company. However, the rates charged and terms and conditions for the movement of gas in interstate commerce through certain intrastate pipelines and production area hubs are subject to regulation under the Natural Gas Policy Act of 1978 ("NGPA"). Pipeline and hub 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 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, 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. 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.
Through many interstate pipeline specific orders, FERC has revised its policy regarding jurisdiction over gathering facilities and services. 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 FERC's policy. As a result of the court's decision, the Texas Railroad Commission conducted inquiries regarding the scope of its regulation of gathering facilities and services. The Company owns several gathering systems in Texas. In 1996, the Texas Railroad Commission initiated a rulemaking and ultimately issued new regulations regarding gathering activities. Although the new regulations increased the regulatory burden to a limited extent, the regulations have not had a significant impact on the Company's gathering activity. It is also possible that other states where the Company owns gathering facilities will become more active in the regulation of gathering activities.
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 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 being 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 that may be removed from these 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 is subject to various laws and regulations governing its other international operations. The Company's other international operations can be affected from time to time by political developments and laws and regulations in the countries where it operates, such as the forced divestiture of assets, production restrictions, import and export controls, price controls, changes in taxes, royalties and other amounts payable to governments, retroactive tax and royalty claims, expropriation of property, cancellation of contract rights and concessions by host governments, foreign exchange rate changes, restrictions as to currency conversion, tariffs and other international trade restrictions and environmental regulations. The likelihood of such occurrences is not predictable.
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 liabilities with respect to sales of the Company's production of certain fuels produced from non-conventional 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 must be sold before January 1, 2003.
The basic credit which 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 $48 per barrel. The natural gas production from wells drilled on certain of the Company's properties in the Moxa Arch and Wamsutter areas in Wyoming, the Carthage field in eastern Texas, the Ozona field in western Texas and certain areas in the Austin Chalk trend qualifies for this tax credit. The Company recorded approximately $17.9 million of Section 29 tax credits in 1999. 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 liabilities 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.
TEXAS SEVERANCE TAX REDUCTION
Natural gas produced from wells that have been certified as deep wells or geologic formations certified as tight formations 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 percent severance tax in Texas on natural gas and NGLs produced by such wells. Such exemption ends August 31, 2001. The natural gas production from wells drilled on certain of the Company's properties, primarily in the Austin Chalk trend and fields in East and West Texas, 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, 2010 are entitled to receive a severance tax reduction. For the maximum tax rate reduction, operators must file by the later of 180 days after first production or the 45th day after approval by the Texas Railroad Commission. 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 reduction. This tax rate reduction remains in effect for ten years or until the aggregate tax reductions received equal 50 percent of the total drilling and completion costs.
ENVIRONMENTAL REGULATION
The Company's operations are subject to extensive Federal, state, local, provincial and international 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 is now covered by the permitting requirements.
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 "non-hazardous," 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 "Other Matters -- 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 from $10 million to $150 million in the case of onshore facilities and from $35 million to $150 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 owners of 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, issued a final rule in August 1998 implementing OPA requirements. 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 Responsible Parties 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 Regulations. 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. Federal legislation governing environmental performance includes the Canadian Environmental Protection Act and the Navigable Protection Act. In Alberta, environmental compliance is regulated by the Environmental Protection and Enhancement Act. The Waste Management Act established environmental standards in British Columbia. Similarly, the Environmental Management Protection Act governs compliance in Saskatchewan.
International Environmental Regulations. All phases of the oil and gas industry are subject to regulatory oversight by various agencies and regulatory bodies within each country. These governmental bodies provide for the protection of the environment covering such items as emissions control, discharges, permits, cleanups and land use.
EMPLOYEES
The Company had 2,223 employees as of February 29, 2000, 21 of which were not full-time. 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, crude oil and NGLs, 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 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 could 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 otherwise already reserved.
ITEM 2.
ITEM 2. PROPERTIES
PROVED RESERVES
The following table sets forth the proved developed and undeveloped reserves of natural gas, NGLs and crude oil of the Company as of December 31, 1999. Reserve estimates as of December 31, 1999 were prepared by the Company's engineers. 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 ("SEC").
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. Reservoir 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 Company owns fee mineral acreage totaling 9,421 (gross) or 8,474 (net) thousand acres as of December 31, 1999. Of this amount, 7,912 (gross) or 7,722 (net) thousand acres are within the Company's Land Grant area. 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 operating area as of December 31, 1999 is set forth below.
Total Leasehold and Fee Mineral. The total leasehold and fee mineral acreage by operating area as of December 31, 1999 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, 1999, the Company owned a working interest in 9,194 gross gas wells (6,047 net) and 4,106 gross oil wells (2,468 net). Gross wells include 2,265 wells with multiple completions. The Company operated 66 percent of the gross wells in which it owned an interest.
DELEVERAGING PROGRAM -- PROPERTY SALES
In 1998, following the Norcen Acquisition, the Company commenced a deleveraging program designed to reduce the Company's debt. The Company sold approximately $745 million of non-strategic properties and assets in 1998 and 1999. The majority of the proceeds from the property sales, along with the Company's sale of its GPM business segment, were primarily used to retire debt. As a result of the property sales, the Company's reserves were reduced by 704.1 Bcfe in 1998 and 128.5 Bcfe in 1999. A summary of properties that have been sold is as follows:
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
GENERAL
The Company is a defendant in a number of lawsuits and is involved in governmental proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. The Company has also been named as a defendant in various personal injury claims, including numerous claims by employees of third-party contractors alleging exposure to asbestos and asbestos-containing materials while working at the Corpus Christi refinery, which the Company sold in segments in 1987 and 1989. While the Company's management cannot predict the outcome of such litigation and other proceedings, management does not expect these matters to have a materially adverse effect on the consolidated results of operations, financial condition or cash flows of the Company. Discussed below are several specific proceedings.
MINERAL RESERVATION LITIGATION
In August 1994, the surface owners (McCormick, et al.) 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 State District Court, Weld County, Colorado, to quiet title to minerals, including crude oil (in some of the lands) and natural gas. On June 23, 1997, the State District Court granted the Company's motion for summary judgment, holding as a matter of law that the mineral reservations at issue were unambiguous and included all valuable non-surface substances, including oil and gas. The Colorado Court of Appeals affirmed the decision of the State District Court in granting the Company's motion for summary judgment on December 10, 1998 and then denied the surface owners' motion for rehearing. The surface owners then filed a Petition for Writ with the Colorado Supreme Court, which was granted in September 1999. Oral arguments are expected to be heard during the first half of 2000.
ROYALTY LITIGATION
The Company is a defendant in a number of lawsuits in which plaintiffs allege that the Company underpaid royalties to them on crude oil and natural gas production. In addition, certain of such suits allege that the Company has violated antitrust laws and other similar laws. None of this litigation specifies the amount of damages being claimed. This litigation against the Company and others in the oil and gas industry suggests that more suits of this type will be filed against the Company, including, perhaps, suits by other types of interest owners and suits in other jurisdictions. The Company intends to vigorously defend against such litigation, as well as any similar lawsuits subsequently brought against the Company. In the opinion of management of the Company, the outcome of these matters should not have a material adverse effect on the consolidated results of operations, financial condition or cash flows of the Company.
A group of royalty owners purporting to represent all of the Company's gas royalty owners in Texas (Neinast, et al.) was granted class action certification in December 1999, by the 21st Judicial District Court of Washington County, Texas, in connection with a gas royalty underpayment case against the Company. This court did not review the merits of the claims being asserted. The pleadings did not specify the damages being claimed and no evidence has been provided to the Company with respect to the amount of damages being claimed. The Company appealed this class certification decision to the Houston Court of Appeals - First District. This appeal is on an expedited schedule, with the Company filing its brief on March 13, 2000.
During 1999, the Company, together with other oil and gas company defendants, agreed to settle several suits involving allegations of royalty underpayments on crude oil production. These settlements were without any admission of fault or wrongdoing on the part of the Company. The Company's portion of the settlements did not have a material adverse effect on consolidated results of operations, financial condition or cash flows of the Company.
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, 1999.
EXECUTIVE OFFICERS OF THE REGISTRANT
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(a) Mr. Lindahl has held his current position with the Company since July 1999. He was President and Chief Operating Officer from October 1996 to July 1999. He was Executive Vice President -- Operations of the Company from August 1995 to October 1996. Prior thereto, he was Vice President -- Operations for UPRC.
(b) Mr. Blank has held his current position with the Company since August 1997. He was Communications Director for the Speaker of the House of Representatives for the United States from February 1997 to August 1997. Prior thereto, he was President of Hager Sharp, Inc.
(c) Mr. Brittain has held his current position with the Company since March 2000. Prior thereto, he was an Assistant General Counsel of the Company.
(d) Ms. Franklin has held her current position with the Company since August 1995. Prior thereto, she was Director of Executive Leadership and Development for Ameritech, Inc.
(e) Mr. Niemiec has held his current position with the Company since September 1999. He served as Vice President -- Marketing from August 1995 until September 1999. He has been Vice President -- Marketing of UPRC since 1993 and President of Union Pacific Fuels, Inc. ("UP Fuels") from 1990 to March 1999.
(f) Mr. Smith has held his current position as Vice President and Chief Financial Officer with the Company since June 1996 and assumed the role of Treasurer in June 1999. From September 1995 until June 1996, he was Vice President and Controller of Union Pacific Corporation ("UPC"). Prior thereto, he was Vice President -- Finance of Union Pacific Railroad Company.
(g) Mr. Vering has held his current position with the Company since March 1998. From October 1996 until March 1998 he was Vice President -- Exploration and Production Services of the Company. Prior thereto, he was General Manager -- Austin Chalk of the Company.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
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 85. At February 29, 2000, there were 251,952,336 shares of outstanding common stock and approximately 113,400 shareholders of record. At that date, the closing price of the common stock on the New York Stock Exchange was $8.9375.
The Company has paid quarterly cash dividends of $0.05 per share since its initial public offering in October 1995. 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, (i) the Company's financial condition, (ii) funds from operations, (iii) the level of its capital and exploratory expenditures, (iv) future business prospects and (v) other factors deemed relevant by the Board of Directors. Accordingly, there can be no assurance that dividends will be paid. The Company has no current plans to increase or decrease its dividend.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
FIVE-YEAR FINANCIAL SUMMARY
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(a) In 1999, the Company recorded a $157.0 million gain on the GPM Disposition, net of tax and a $3.4 million net of tax extraordinary gain on the early extinguishment of debt.
(b) In 1998, the Company recorded a $760 million after-tax charge related to asset impairments in accordance with Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" ("SFAS No. 121").
(c) In March 1998, the Company acquired Norcen for $2.634 billion.
(d) In November 1995, the Company recorded a $122.5 million pretax ($78.5 million after-tax) gain resulting from the Columbia Gas Transmission Company bankruptcy settlement.
(e) Earnings per share information prior to 1996 has been omitted as the Company was a wholly-owned subsidiary of UPC until the Company's initial public offering in October 1995. Therefore, net income per share is not applicable for periods prior to the fourth quarter of 1995.
(f) 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 prior periods.
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 of this Annual Report. The Consolidated Statement of Income for 1997 has been restated to present the Company's GPM business segment as discontinued operations.
SIGNIFICANT EVENTS
NORCEN ACQUISITION
In March 1998, the Company acquired Norcen for an aggregate purchase price of $2.634 billion, and also assumed long-term debt obligations of Norcen totaling approximately $1 billion. The acquisition was accounted for as a purchase effective March 3, 1998, and, therefore, Norcen's financial results are reflected in the Company's results beginning in March 1998. See Note 2 to the Consolidated Financial Statements.
PROPERTY SALES AND GPM DIVESTITURE
In 1998, following the Norcen Acquisition, the Company commenced a deleveraging program designed to reduce the Company's debt. By December 31, 1998, the Company had sold over $400 million of properties. Properties sold included the Denver-Julesburg Basin in the Rockies (the "DJ Basin"), the Matagorda Island Block 623 Field and surrounding blocks (the "Matagorda property") and other U.S. Offshore, Rockies and certain Canadian properties.
During 1999, the Company continued its deleveraging program. The property sales in 1999 included properties located in Canada's Caroline-Swan Hill field, South Texas, and various properties in East Texas and the Rockies. The Company also monetized a gas co-generation project.
In addition, the Company's sale of the GPM business segment to Duke was completed on March 31, 1999 for $1.36 billion. The GPM business segment was presented as a discontinued operation in the Consolidated Financial Statements. See Note 3 to the Consolidated Financial Statements.
CRUDE OIL AND NATURAL GAS SALES PRICE AND HEDGING LOSSES
During 1998, prices for oil and natural gas declined as a result of several factors. These factors included, but were not limited to, high production levels from members of the Organization of Petroleum Exporting Countries ("OPEC") and other countries, generally mild weather conditions, the economic weakness in several Asian countries and excessive natural gas storage levels. These prices were 29 percent and 10 percent, respectively, below the corresponding price strips on December 31, 1997.
During 1999, prices for crude oil and natural gas increased. Members of OPEC and other countries lowered crude oil production levels and natural gas storage levels declined. The Company was unable to take full advantage of the price increases, primarily due to solvency-based oil hedges that were put into place at an average price of $14.50 per barrel. Those hedges, which expired in December 1999, lowered revenues and operating income by about $178.1 million during 1999.
IMPAIRMENT OF LONG-LIVED ASSETS
The Company recorded a pretax charge of $1.23 billion ($760.1 million after tax) in the fourth quarter of 1998, as required by SFAS No. 121. The non-cash asset impairment charge to earnings was recorded as DD&A expense of $1.17 billion and surrendered lease expense of $54.5 million in the Company's Consolidated Statement of Income. Low hydrocarbon prices at the end of 1998 -- particularly their effect on the value of the Company's heavy oil properties in Canada and Guatemala -- and reserve revisions following a comprehensive review of reserves completed in December 1998, were the principal factors contributing to the impairment. Most of the reserve revisions were associated with properties in Canada and U.S. Offshore that were acquired by the Company in 1998. The revisions also reflect disappointing well performance from discoveries that were not on production at the time of the Norcen Acquisition.
In 1999, the Company recorded a pretax charge of $120.6 million for impairment of assets. The non-cash asset impairment charges to earnings were recorded as DD&A expense of $70.6 million and surrendered lease expense of $50 million in the Company's Consolidated Statement of Income. Reserve revisions following a comprehensive review of reserves was the principal factor contributing to $70.6 million impairment of producing properties. These properties were primarily in the Gulf Coast Onshore area. Surrendered lease expense of $50.0 million was recorded for the Delta Centro project in Venezuela as a result of a $9.2 million dry hole drilled on the prospect in 1999.
CORPORATE REORGANIZATION AND REDUCTION IN FORCE
As a result of the low price environment in 1998 and the resulting reduction in cash flows generated by the Company's operations, the Company recorded a pretax charge in 1998 of $17 million to cover the cost of a workforce reduction at its Fort Worth, Texas headquarters and other domestic locations, and costs associated with an offshore rig commitment.
During the first quarter of 1999, the Company reorganized its operating groups, announced workforce reductions for its Canadian and U.S. operations and established an early retirement program. As a result of these actions, the Company recorded a $14.5 million restructuring charge. The charge included $7.3 million for severance costs and excess office space commitments, an additional $4.2 million liability for pension and other postretirement benefits in connection with the early retirement program and a $3.0 million valuation allowance for specialty drilling equipment and supplies no longer required for cancelled drilling programs. The charge was partially offset by the $3.1 million reversal of the 1998 charge associated with the offshore rig commitment.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1999 COMPARED TO DECEMBER 31, 1998
SUMMARY FINANCIAL DATA
The Company recorded net income of $225.8 million ($0.91 per share) in 1999, compared to a net loss of $898.7 million ($3.63 per share) in 1998. The improvement was largely due to the recording of a $1.23 billion ($760.1 million after-tax) SFAS No. 121 asset impairment in 1998, and a $157.0 million after-tax gain on the 1999 sale of the GPM business segment to Duke. In addition, higher commodity prices combined with cost reduction programs contributed to improved results from continuing operations. A $3.4 million after tax extraordinary gain was also recorded in 1999 on the extinguishment of debt. Restructuring charges related to corporate reorganization and reductions in force were included in the results of both 1999 ($11.4 million) and 1998 ($17.0 million).
RESULTS OF CONTINUING OPERATIONS
The Company recorded income from continuing operations of $89.2 million for 1999 compared to a loss of $883.1 million last year, with earnings per share of $0.36 in 1999 up from a loss of $3.57 per share a year ago. Included in 1998 results was a charge of $1.22 billion ($756.0 million after-tax) related to the asset impairment. Higher prices contributed $132.4 million to income, while significant cost reductions were achieved as a result of cost control programs, property sales and workforce reductions. These reductions resulted in a $65.2 million decrease in lease operating costs and substantially lower overhead costs. Interest costs declined by $31.1 million due to the debt reduction resulting from the use of proceeds from the Company's aggressive deleveraging program and the GPM Disposition. The Company also recorded $58.1 million after tax income for tax settlements in the United States and Canada and $97.5 million after tax in higher gains from foreign currency remeasurement. Offsetting these benefits were the impacts of lower volumes of $196.5 million, lower minerals income of $15.7 million, lower gains on assets sales of $49.5 million and a $43.4 million charge for natural gas firm transportation obligations associated with the GPM Disposition.
SUMMARY OF SEGMENT FINANCIAL DATA
Operating income increased by $1.33 billion to $135.8 million for the year. Exploration and production operating income, excluding the $1.22 billion 1998 asset impairment charge, increased by $104.1 million to $122.5 million. Lower volumes reduced operating income by $196.5 million, while gains on sales of assets and
investments decreased by $21.0 million largely due to the sale of the Matagorda property in 1998. Price improvements added $132.4 million to revenues, while exploration and production expenses decreased by $60.3 million, associated with reduced capital spending, lower volumes, cost saving initiatives, and the restructuring of the Company. DD&A expenses, excluding impairments declined by $201.8 million, caused by both lower volumes ($121.8 million) and DD&A per unit rates ($80.0 million).
Minerals operating income decreased by $15.7 million to $117.8 million. Black Butte equity income was down by $7.3 million to $79.3 million, primarily due to coal contract obligations which were delayed until 2000, offset by the absence of a $14.3 million accrual for a legal settlement in 1998. Coal royalties declined by $3.7 million due to lower volumes of coal extracted and sold from Company property. (See "Outlook and Other Matters" regarding Black Butte equity income and a coal contract that expires in 2000). In addition, soft market conditions for soda ash resulted in lower prices and a $4.6 million decline in equity income and soda ash royalties, while lower future uranium mine reclamation costs provided a $4.0 million offsetting income benefit.
General and administrative ("G&A") expenses decreased by $23.0 million, reflecting lower legal costs and cost savings related to the reductions in force that occurred in late 1998 and early 1999. Restructuring charges affected both years -- $11.4 million in 1999 and $17.0 million in 1998. The 1999 reduction in G&A was partially offset by $11.2 million of payroll expense related to the vesting of the January 1999 retention stock awards.
EXPLORATION AND PRODUCTION OPERATIONS
Operating Revenues
Exploration and production revenues decreased by $64.1 million (4%) to $1,473.3 million for 1999, due to a $196.5 million reduction associated with lower volumes, partly offset by a $132.4 million increase associated with higher product prices. Other oil and gas revenues decreased by $28.8 million largely due to $49.5 million in lower gains on property sales, offset by $28.5 million of gains on the disposition of a gas co-generation project. Hedging positions in both crude and natural gas products reduced revenues by $178.1 million for 1999 compared to a reduction of $9.0 million for 1998.
Exploration and production volumes of 2,151.6 MMcfed decreased by 315.4 MMcfed (13%) from 1998 results primarily due to property sales (approximately 153 MMcfed) and production declines related to reduced capital spending levels. Results for 1998 include only ten months of results from properties acquired through the Norcen Acquisition.
U.S. Onshore volumes decreased by 236.5 MMcfed, reflecting the decline in capital spending and effects of property sales, which contributed 58 MMcfed to the decrease. U.S. Offshore volumes decreased by 42.9 MMcfed as the impact of property sales (approximately 35 MMcfed) and production declines offset the full year of production from properties acquired through the Norcen Acquisition. Canadian volumes decreased by 56.9 MMcfed primarily related to the impact of property sales (approximately 60 MMcfed) that were partially offset by the full year of production from properties acquired through the Norcen Acquisition. Other International volumes improved 20.9 MMcfed over 1998, primarily due to the inclusion of the full year of volumes in 1999 from properties acquired through the Norcen Acquisition.
Natural gas volumes decreased by 162.3 MMcfd to 1,278.8 MMcfd during 1999, principally reflecting reduced capital spending levels, property sales and production declines for existing properties, offset by the inclusion of a full year of volumes from properties acquired through the Norcen Acquisition. Total United States volumes declined by 159.7 MMcfd, while Canada volumes decreased by 3.4 MMcfd.
Natural gas liquid volumes decreased by 4.7 MBbld to 28.4 MBbld. The decline is largely related to the sales of the offshore Matagorda property in the third quarter of 1998 and the South Texas and the Canadian Caroline-Swan Hill properties in early 1999, as well as production declines resulting from reduced capital spending levels. Partially countering the decline was ethane recovery in the U.S. Onshore for most of 1999.
Crude oil volumes declined by 20.8 MBbld to 117.1 MBbld for 1999. The decrease reflects property sales as well as production declines in U.S. Onshore and Canada, offset by the full year of Norcen property volumes in 1999. U.S. Onshore volumes declined by 15.8 MBbld, while Canada volumes decreased by 6.6 MBbld. Other International volumes improved 3.3 MBbld largely due to the inclusion of the full year of production from properties acquired through the Norcen Acquisition.
Operating Expenses
Production expenses, which include lease operating costs, production severance and property taxes, and production overhead, were $400.6 million for 1999, down $43.7 million from last year. Production costs per unit increased from $0.49 per Mcfe last year to $0.51 per Mcfe for 1999, reflecting the impacts of production declines and higher production taxes caused by higher prices. Total lease operating costs declined by $65.2 million primarily due to property sales and cost reduction efforts initiated in late 1998. Included in the lease operating cost decline were lower costs for personnel, workovers, maintenance and repairs and salt water disposal. The reduction was significant as 1999 results include the full year of expenses related to the properties acquired through the Norcen Acquisition. Lease operating expenses on a per unit basis dropped from $0.34 per Mcfe in 1998 to $0.31 per Mcfe. Production severance and property taxes increased by $23.8 million from last year, reflecting increased product prices for U.S. Onshore and Guatemalan operations, as well as $8.2 million related to severance tax audit adjustments. Production overhead costs decreased by $2.3 million from 1998, despite $3.6 million of production overhead costs related to the vesting of the January 1999 retention stock awards. The majority of the overhead savings in 1999 was the result of lower personnel and related costs in connection with the reductions in work force.
Exploration expenses of $267.9 million decreased by $71.1 million from last year, primarily due to the Company's reduced capital spending program. Dry hole expenses decreased by $17.2 million, geological and geophysical costs were $30.5 million lower and other surrendered lease costs dropped $13.4 million. Included in 1999 dry hole expenses was $24.0 million related to a well that was reclassified to an exploratory dry hole in the fourth quarter of 1999. Exploration overhead costs declined by $6.2 million primarily from reductions in personnel ($2.1 million) and computer costs ($2.9 million) caused by work force reductions.
DD&A costs for exploration and production properties declined by $1.3 billion from last year to $816.0 million. Included in the 1999 results was $65.1 million, primarily related to the impairment of certain U.S. Onshore properties, while 1998 results included $1,163.1 million related to producing property impairments. Excluding the impairments, lower production volumes caused a $121.8 million reduction, while lower DD&A rates produced an $80.0 million decline. DD&A per unit rates decreased from $1.06 per Mcfe last year to $0.96 per Mcfe in 1999 largely due to the asset impairment recorded by the Company in 1998.
MINERALS OPERATIONS
Operating income for minerals declined by $15.7 million from last year. Equity income from the Black Butte joint venture declined by $7.3 million reflecting lower volumes resulting from postponement of contract obligations until 2000, partially offset by the absence of a $14.3 million accrual in 1998 for a legal settlement (See "Outlook and Other Matters" regarding the Black Butte Contract expiration in 2000). Coal royalty income decreased by $3.7 million from lower volumes as mining operations focused on Federal sections, and soda ash royalties decreased by $4.6 million reflecting soft conditions in the soda ash market. Operating income at the Company's soda ash joint venture was down $4.6 million, also related to the soft conditions in the soda ash market. Results in 1999 also include a $4.0 million reserve release related to lower reclamation requirements and a $5.5 million impairment charge, while results from 1998 include a $2.0 million gain on the sale of industrial mineral properties and a $4.0 million asset impairment charge.
GENERAL AND ADMINISTRATIVE AND OTHER INCOME/EXPENSE
General and administrative expenses (including DD&A) of $104.5 million decreased by $23.0 million from 1998. Restructuring charges affected both years -- $11.4 million in 1999 and $17.0 million in 1998 -- both related to a corporate reorganization and reductions in work force. Included in 1999 general and administrative expenses were $11.2 million of payroll expense related to the vesting of the January 1999 retention stock awards. Contributing to lower costs in 1999 were benefits in several cost categories reflecting savings from the late 1998 and early 1999 reductions in force, early retirement programs and the GPM Disposition. These savings contributed to declines of $5.2 million in salaries and benefits, $4.2 million in computer costs, $3.0 million in professional and temporary services and $1.7 million in rent expense. In addition, legal costs decreased by $2.8 million and donations decreased by $2.1 million.
Other income/expense -- net increased by $77.0 million over 1998 to income of $31.7 million for 1999. Causing the majority of the improvement was 1999 foreign currency gains of $44.2 million primarily related to the remeasurement of U.S. dollar denominated debt in Canada, while 1998 results included a $46.5 million charge related to the same issue. Interest income increased by $19.4 million to $30.5 million in 1999, principally related to interest income from the Canadian ($7.1 million) and UPC ($20.5 million) tax settlements. Also included in 1999 results was a charge of $43.4 million for natural gas firm transportation
contract obligations. Results in 1998 included a $14.3 million charge related to the expiration of interest rate lock contracts intended to hedge interest rates for a contemplated bond issuance, and an $11.0 million gain on the closure of a foreign exchange contract entered into in connection with the 1998 Norcen Acquisition.
Interest expense declined by $31.1 million to $218.7 million in 1999, reflecting reduced debt balances partly offset by higher interest rates on fixed rate debt. The debt reduction is primarily the result of the use of proceeds from the sale of the GPM business segment to pay down debt at the end of March 1999, as well as other actions taken to reduce debt since mid-1998 in connection with the Company's deleveraging program. Interest expense in 1998 included only ten months of interest on debt from the Norcen Acquisition, completed on March 3, 1998.
The income tax benefit from continuing operations declined by $464.8 million to $140.4 million for 1999. Lower pretax loss from continuing operations, primarily due to the 1998 SFAS No. 121 asset impairment charge, which had provided a tax benefit of $464.6 million in 1998. Included in 1999 results were benefits of $27.9 million related to a Canadian tax settlement and $11.9 million related to a tax settlement with UPC (See Note 8). Also offsetting the decline, was the recording of $28.1 million of favorable tax adjustments in 1999 primarily related to prior years and a $9.2 million reduction in state taxes. Section 29 credits were $17.9 million in 1999 and $16.4 million in 1998, while 1999 also included $29.3 million of foreign currency gains related to the remeasurement of deferred tax liabilities in Guatemala and Venezuela, compared to gains of $22.5 million included in 1998.
RESULTS OF DISCONTINUED OPERATIONS
Income from discontinued operations, net of taxes, was $133.2 million for 1999, an increase of $148.8 from 1998 results. The variance is due to the $157.0 million after-tax gain from the GPM Disposition. GPM business segment operating loss for 1999 was $23.8 million after-tax primarily due to a $21.5 million pretax charge related to firm transportation contracts that were marked to market, as well as lower margins and product prices.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1998 COMPARED TO DECEMBER 31, 1997
SUMMARY FINANCIAL DATA
The Company recorded a net loss of $898.7 million in 1998, or a loss of $3.63 per share, compared to net income of $333.0 million, or $1.33 per share, in 1997. The decrease is primarily due to the impact of the SFAS No. 121 asset impairment of $1.23 billion ($760.1 million after tax), the majority of which affected continuing operations, and lower product prices.
RESULTS OF CONTINUING OPERATIONS
In 1998, the Company reported a net loss from continuing operations of $883.1 million, compared to income from continuing operations of $303.1 million in 1997. Included in 1998 results was a charge of $1.22 billion ($756.0 million after tax) for the asset impairment. The additional volumes from the Norcen Acquisition added revenues of $456.7 million, while depressed product prices reduced revenues from non-Norcen properties by more than $200 million as average prices declined 22 percent. Additional factors that impacted income, primarily driven by the Norcen Acquisition, were $273.9 million of higher production, exploration and administrative expenses and $210.3 million of higher interest expense. Included in administrative expenses was a restructuring charge of $17.0 million related to a reduction in force of the Company's domestic operations. The Company realized a $140.0 million improvement to operating income as a result of gains on the sale of various properties.
SUMMARY OF SEGMENT FINANCIAL DATA
The operating loss was $1,193.2 million in 1998 compared to operating income of $433.9 million in 1997. Exploration and production operating income, excluding the asset impairment related to such properties, declined by $355.1 million to $18.3 million. These results reflect lower prices for all products and increased operating, exploration and DD&A costs, which offset higher volumes and the gains on the sale of various properties. Minerals operating income dropped slightly to $133.5 million due to a $14.3 million accrual for a legal settlement and a $4.0 million asset impairment but was partially offset by increased operating income due to an amended coal supply agreement at Black Butte. General and administrative expenses, excluding the restructuring charge, increased by $35.5 million primarily due to increased administrative expenses associated with expanded Canadian and Other International operations and an $8.2 million charge related to the settlement of various crude royalty and tax issues.
EXPLORATION AND PRODUCTION OPERATIONS
Operating Revenues
Exploration and production revenues increased by $243.9 million (19%) to $1,537.4 million, $456.7 million of which were associated with properties added in the Norcen Acquisition. Excluding the Norcen
Acquisition properties, volumes were essentially flat to 1997 production levels; however, product price declines reduced revenues by $211.0 million. Other oil and gas revenues increased by $77.8 million from higher gains on property sales, principally the sales of the DJ Basin and the Matagorda property.
Exploration and production volumes improved by 851.3 MMcfed to 2,467.0 MMcfed in 1998. Canada volumes were 481.0 MMcfed higher than last year, while Other International volumes increased by 244.1 MMcfed, in both cases primarily due to properties added in the Norcen Acquisition. Production from domestic properties increased by 126.2 MMcfed including 97.2 MMcfed added in U.S. Offshore largely from the Norcen Acquisition which offset the sale of the Matagorda property. U.S. Onshore realized an increase of 54.5 MMcfed in 1998.
Natural gas volumes increased by 332.6 MMcfd (30%). Canada volumes increased by 263.6 MMcfd and U.S. Offshore production was up 64.1 MMcf, largely due to properties added in the Norcen Acquisition. U.S. Onshore production was essentially flat due to declines in the Austin Chalk area that offset improvements in all other areas.
Natural gas liquids volumes increased by 1.4 MBbld (4%) to 33.1 MBbld. Production improvements included 2.5 MBbld in Canada largely due to the Norcen Acquisition. This increase was partially offset by lower volumes from the U.S. Onshore as a result of the decision to reject ethane and bypass gas due to low NGL prices.
Crude oil volumes were 85.0 MBbld higher in 1998 primarily from properties added in the Norcen Acquisition. Canada production was 33.7 MBbld higher for 1998, while additional production from Guatemala and Venezuela was 20.8 MBbld and 16.7 MBbld, respectively. U.S. Onshore production was up 8.0 MBbld.
Operating Expenses
Production expenses increased by $143.5 million while production costs on a per unit basis were $0.49 per Mcfe, 4 percent less than last year's $0.51 per Mcfe. Total lease operating expenses rose by $141.3 million, of which $135.4 million was attributable to Norcen Acquisition properties. Lease operating expenses on a per unit basis were up 22 percent to $0.34 per Mcfe which reflects higher operating expenses associated with the production of heavy crude oil in Guatemala, Venezuela and Canada. Production overhead costs were up $2.6 million largely because of increased personnel costs due to the expanded international operations.
Exploration expenses in 1998 increased by $134.3 million over 1997, including $54.5 million of surrendered lease costs that were part of the SFAS No. 121 asset impairment. Excluding the effect of the asset impairment, activity related to properties added in the Norcen Acquisition contributed $72.8 million to the increase. For domestic operations, exploration expenses were up 3 percent to $210.8 million, excluding the surrendered lease asset impairment.
DD&A increased by $1,616.5 million, including $1,163.1 million related to the SFAS No. 121 asset impairment. On a per unit basis, DD&A expense, excluding the asset impairment, rose $0.21 per Mcfe to $1.06 per Mcfe. Properties added in the Norcen Acquisition contributed $377.4 million, excluding the asset impairment. The remaining variance from non-Norcen Acquisition properties, $76.0 million, is associated with higher volumes that caused $11.3 million of the total increase in DD&A, while a higher per unit rate added $64.7 million.
MINERALS OPERATIONS
Minerals operating income decreased by $2.0 million. Contributing to the decline was $14.0 million of lower operating income from soda ash operations, reflecting lower royalties, lower equity income from the Company's soda ash joint venture and the inclusion of a lease bonus in 1997 results. Also affecting 1998 performance was a $14.3 million accrual for a legal settlement and a $4.0 million asset impairment on certain industrial mineral and uranium properties. Partly offsetting these items were $19.7 million of higher equity income from Black Butte reflecting the amendment of a coal supply contract and a $2.0 million gain from a property sale.
GENERAL AND ADMINISTRATIVE AND OTHER INCOME/EXPENSE
General and administrative expenses increased by $52.5 million to $127.5 million, principally reflecting $21.1 million related to expanded international operations and the $17.0 million restructuring charge. Also contributing to the increase was an $8.2 million charge related to the settlement of various crude royalty and tax issues, $3.3 million of additional rent expense, $2.4 million in higher professional and temporary costs, and a $1.9 million rise in DD&A expense for domestic overhead. On a per unit basis, excluding the restructuring charge, G&A expenses were flat as compared to 1997 at $0.12 per Mcfe.
Other income/expense was $69.8 million lower than 1997 results. The reduction reflects a $46.5 million foreign currency exchange rate loss and a $14.3 million charge related to the expiration of interest rate lock contracts intended to hedge such rates for a contemplated bond issuance. In addition, 1997 results included the benefit of a $23.0 million partial reduction of reserves associated with the 1994 sale of the Wilmington, California oil field, due to the reduction of environmental remediation exposure, a $7.2 million gain on the sale of securities held for investment and $6.7 million of higher environmental insurance settlements. Partly offsetting these declines were an $11.0 million gain on the closure of a foreign exchange contract entered into in connection with the Norcen Acquisition and the inclusion in 1997 of $17.8 million of costs related to the unsuccessful bid to acquire Pennzoil Company.
Interest expense increased by $210.3 million to $249.8 million. This increase reflects the borrowings made in connection with the Norcen Acquisition and capital spending programs. Interest expense allocated to discontinued operations was $21.1 million in 1998 and $13.6 million in 1997.
Income taxes declined by $721.0 million from 1997 to a benefit of $605.2 million, primarily the result of the pretax net loss in 1998. Included in 1998 results was a $22.5 million benefit due to foreign currency gains on deferred tax liabilities in Venezuela and Guatemala. Section 29 tax credits in 1998 were $16.4 million compared to $18.8 million in 1997. The effective tax rate in 1998 was 40.6 percent versus 28.6 percent in 1997 largely due to the effect of the acquisition and expansion of operations outside the United States where higher tax rates exist.
RESULTS OF DISCONTINUED OPERATIONS
Results from discontinued operations generated a net loss of $15.6 million for 1998, compared to income of $29.9 million in 1997. The segment reported an operating loss of $1.0 million for 1998 versus operating income of $61.3 million in 1997. Operating margins decreased by more than $45.0 million from 1997 due to low product prices that were not offset by lower gas purchase prices. Operating revenues decreased by $66.7 million from 1997 largely due to the $35.2 million ($23.0 million after tax) charge related to firm transportation contracts that were marked to market in connection with the GPM Disposition, and lower product prices. Volumes were up two percent while other benefits to income include the $30.0 million pretax gain on the settlement of a gas supply agreement and lower operating expenses that decreased by $17.9 million.
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary sources of cash during 1999 were cash provided by operations, long-term debt issuance and proceeds from the GPM Disposition and other assets associated with the Company's deleveraging program. Cash outflows for 1999 included the repayment of debt, capital and exploratory expenditures, interest and dividends.
Cash from operations of $995.5 million was $35.6 million lower than in 1998. Higher prices provided $132.4 million, while lower volumes caused a reduction of $196.5 million. Improvements were also achieved, primarily from tax settlements ($65.9 million), lower lease operating costs ($65.2 million) and interest expense ($31.1 million), as well as favorable results from the Company's cost control programs. However, these improvements were offset by lower minerals income, cash payments related to restructuring charges and unfavorable changes in other working capital items.
Cash provided by investing activities was over $1.0 billion in 1999, up from a usage of $3.3 billion last year. During 1999, the Company received proceeds of $1.36 billion from the GPM Disposition, while 1998 included a $2.6 billion payment for the acquisition of Norcen. Proceeds from sales of assets and other investments of $281.3 million were $203.7 million lower than 1998, primarily reflecting higher 1998 property sales and asset monetizations in connection with the Company's deleveraging program. Discontinued operations required a use of cash of $203.6 million in 1999 compared to providing a $50.4 million source of cash in 1998.
Capital and exploratory expenditures from continuing operations (excluding the Norcen Acquisition) decreased by $766.3 million from $1.2 billion in 1998 to $428.2 million for 1999, reflecting the Company's effort to control capital spending in light of depressed product prices early in 1999 and to achieve debt reduction goals. The 1998 amounts set forth below include capital expenditures for Norcen properties beginning in March.
CAPITAL AND EXPLORATORY EXPENDITURES
Exploration and production capital spending was down by $738.8 million to $423.1 million, principally reflecting the effort to control capital spending in light of depressed product prices early in 1999 and to achieve debt reduction goals. The major categories of capital spending included development drilling ($232.6 million), other development capital ($97.2 million) and exploratory drilling ($36.6 million). Exploration and development drilling by area included $143.0 million in U.S. Onshore, $32.5 million in U.S. Offshore, $74.0 million in Canada and $19.7 million in Other International, including $11.6 million in Venezuela. Minerals, G&A and other capital was down $27.5 million to $5.1 million as spending in 1998 included costs related to the Fort Worth office relocation.
As of December 31, 1999 and 1998, the total capitalization of the Company was as follows:
At year-end 1998, the Company had three debt facilities totaling an aggregate of U.S. $2.5 billion. These facilities were comprised of a $1.0 billion 364-Day Competitive Advance/Revolving Credit Agreement (the "Bridge Facility"), a $750 million 364-Day Competitive Advance/Revolving Credit Agreement and a $750 million Competitive Advance/Revolving Credit Agreement ("Long-Term Facility") expiring in October 2003.
In April 1999, the Company issued $500 million of notes and debentures comprised of $200 million 7.3% Notes due April 2009 and $300 million 7.95% Debentures due April 2029. The notes and debentures were issued under the Company's existing $1.0 billion shelf registration statement, of which $500 million remains available.
During the first half of 1999, commercial paper, supported in part by the Company's Bridge Facility, was repaid using proceeds from the Company's deleveraging program and the GPM Disposition and the issuance
of the long-term notes and debentures. The Bridge Facility was terminated in April 1999. The $750 million 364-Day Competitive Advance/Revolving Credit Agreement expired in October 1999, leaving the Company with the Long-Term Facility at year-end 1999. The Long-Term Facility contains a covenant stipulating that the ratio of consolidated debt to consolidated EBITDAX -- the sum of operating income (before adjustments for income taxes, interest expense or extraordinary gains or losses), depreciation, depletion and amortization and exploration expenses -- cannot exceed 3.25:1.00. The Long-Term Facility also places other restrictions on the Company regarding the creation of liens, incurrence of additional indebtedness by subsidiaries, transactions with affiliates, sales of stock of Union Pacific Resources Company (a wholly-owned subsidiary of the Company) and certain mergers, consolidations and asset sales. The Company was in compliance with the covenant provisions at year-end 1999 and 1998.
The 2005, 2008 and 2009 Notes and the 2018, 2028 and 2029 Debentures are redeemable as a whole or in part, at the option of the Company at any time. The redemption price is equal to the greater of (i) 100% of the principal amount of the securities to be redeemed or (ii) the sum of the present values of the remaining scheduled payments thereon, discounted to the redemption date on a semi-annual basis at the Treasury Rate, plus a stated basis point spread and accrued interest on the principal amount being redeemed to the redemption date. There are no other notes or debentures redeemable prior to maturity. None of the Company's notes and debentures is subject to a sinking fund requirement. At December 31, 1999, the Company had an effective shelf registration statement on file with the Securities and Exchange Commission that would permit the Company or certain identified subsidiaries to offer up to $500 million in debt, equity and/or other securities.
During 1999, the Company purchased on the open market and retired long-term debt with a face value of $94.5 million at a discount prior to maturity. The retirement of long-term debt due to the repurchases resulted in an extraordinary gain of $3.4 million, net of $1.8 million of tax. The gain on the retirement was classified as a gain from an extraordinary item on the Consolidated Statement of Income. The Company may, at its discretion, make additional open market purchases of debt prior to maturity.
At December 31, 1999, $135.1 million of commercial paper and bankers' acceptances were classified as long-term. This classification reflects the Company's intent and ability to maintain these borrowings on a long-term basis, supported by the Long-Term Facility, through the issuance of additional commercial paper and/or new term financings. Debt maturities through 2004, excluding capital leases, are $135.1 million of bankers' acceptances due in 2000 and $250 million of debentures due July 2, 2002.
The fair value of the Company's long-term debt, excluding commercial paper and bankers' acceptances, debt discount/premium and capital lease obligations was approximately $2,467 million at December 31, 1999 and $2,088 million at December 31, 1998. The fair value was estimated using quoted market prices. These fair values were trading at a discount to their face value of 93.8% at December 31, 1999 and 1998.
In April 1999, the Company's senior unsecured credit ratings were downgraded by Standard & Poor's to BBB-, and by Moody's to Baa3. Its commercial paper ratings were downgraded by Standard & Poor's to A3 and by Moody's to P3. Fitch IBCA has continued to rate the Company's senior unsecured credit with a BBB+ rating and its commercial paper with a rating. The Company expects these ratings to improve as debt is paid down.
The Company has guaranteed a portion of the OCI Wyoming, L.P. debt facility. At December 31, 1999, OCI Wyoming, L.P. had an outstanding debt facility balance of $30 million, of which the Company has guaranteed $14.7 million.
The Company utilizes letters of credit to support certain financing instruments, performance contracts and insurance policies. The fair value of the letters of credit at December 31, 1999 and 1998 was $41.3 million and $58.6 million, respectively.
During 1998, the Company purchased $26.7 million of its common stock. During 1999, the Company paid quarterly cash dividends of $0.05 per share on its outstanding common stock, and on October 21,1999, declared a $0.05 per share dividend that was paid on January 2, 2000. 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 facts deemed relevant by the Board of Directors. Accordingly, there can be no assurance that dividends will be paid.
OUTLOOK AND OTHER MATTERS
The Company expects its average oil and gas production to decline slightly in 2000 compared to 1999. Production declines during the first part of 2000 are expected to be reversed in the second half of 2000 and following years, as the Company increases its capital spending and new projects are completed and placed into service. The Company's proved reserves declined by about seven percent in 1999. The Company's ability to replace reserves in 1999 was impacted by the postponement of the Mississippi Canyon Block 755 ("Gomez") deep-water offshore prospect until 2000, together with the declines related to reduced capital spending in 1999. The Company's reserve replacement costs were $0.91 per Mcfe, which was below its five year average of $1.10 per Mcfe. In 2000, the Company expects to modestly grow its reserves through development drilling programs and to continue to pursue exploration opportunities.
Prices for crude oil, natural gas and NGLs in the first quarter of 2000 were higher than historic average hydrocarbon prices. NYMEX crude oil prices have risen sharply from about $10 per barrel in early 1999 to over $30 per barrel in early 2000, as the demand for crude oil has exceeded worldwide production and inventory. Reduced crude oil production by members of OPEC and an increase in consumption of crude oil in Asian countries resulting from their improved economies have contributed to the greater demand for crude oil. The increase in natural gas prices in the first quarter of 2000 reflects the tight natural gas supplies compared to United States demand. Cold weather in early 2000 in the northeast United States, an increase in demand for the industrial use of natural gas and lower production resulting from the decline in drilling in prior years have contributed to the draw down in gas inventory supplies. The Company expects prices to remain high in 2000; however, price fluctuations could affect expected future net income, cash flows, capital spending and debt reduction. For 2000, the Company has reduced some of its exposure to lower prices by purchasing puts and fixed price contracts and limited some of the upside of higher prices by selling calls and fixed price contracts. Slightly more than one-half of the Company's estimated 2000 production was hedged in early 2000.
The Company plans to increase its capital spending in 2000 from the $428 million spent in 1999 to approximately $650 million for exploration and development projects. The Company plans an additional $100 million for select property acquisitions. The capital program will be funded through cash provided by operations. Almost 83 percent of the capital budget will be focused on the development of fields which have already been proved and which are expected to provide more immediate cash flow with low risk. The remainder of the Company's budget will be for select exploration projects and other development drilling that has the potential for long-term impact. Both the development and exploration programs will employ the Company's ongoing strategy of applying its expertise in advanced drilling and completion technologies. Approximately 38 percent of the capital budget will be invested in U.S. Onshore, 29 percent in Canada, 14 percent in U.S. Offshore and 19 percent in Other International. The Company may adjust its capital spending as commodity prices and cash flows change. The extent and timing of capital spending may also be affected by changes in business, financial and operating conditions as well as by the timing and availability of suitable investment opportunities. See "Outlook and Other Matters."
In U.S. Onshore, the Company plans to drill delineation wells in the Etouffee discovery area in South Louisiana and a well in its Turtle Soup prospect near the Etouffee discovery. Using its horizontal drilling expertise, the Company plans to expand its success in the Frontier area of the Green River Basin in the Land Grant. After its success in 1999 with the Rock Island 4H, the Company made plans to drill four additional wells in the deep over-pressured Frontier formation to further understand the formation's potential. These wells include the Table Rock 115H, Sage Flat Unit 7H, Sidewinder 1H and Sidewinder 2H. Although several of the wells drilled in early 2000 near the Rock Island 4H were not successful, the formation's resources are large so the Company will continue to test the Frontier formation during 2000 to further understand its potential. In the U.S. Offshore, the Company plans to drill an exploration well at Garden Banks Block 700 and a Green Canyon Block 281 exploration well. Additionally, the Company plans to drill another well during 2000
at its Gomez discovery. In Canada, the Company expects to start producing its 1999 Klua discovery well and is set to spud an adjacent well in the northeast British Columbia territory. An exploratory well at the Sullivan Creek prospect in southwestern Alberta is also planned during the second half of 2000. The Company is continuing its Canadian heavy oil drilling program which began in the fourth quarter 1999. In Guatemala, the Company plans to drill step-out wells in the Xan area in addition to a high potential impact exploratory well at the Libertad prospect in 2000. The Company plans to increase its spending and drilling activity in Venezuela by drilling 24 wells in the Oritupano-Leona concession area and increase its facility capacity.
The Company expects to continue to improve its balance sheet by reducing debt by at least $200 million in 2000. The Company expects its cash from operations to be approximately $1 billion for 2000, assuming a NYMEX price forecast of $26 per barrel for crude oil and $2.70 per Mcf for natural gas. To the extent that cash from operations is generated in excess of this forecast or due to proceeds from the monetization of its minerals business or the sales of assets, the additional cash could be used to further reduce debt and/or initiate a common stock repurchase program if approved by the Board of Directors. The Company expects to experience lower interest expense in its Consolidated Statement of Income in future years as a result of its debt reduction program.
The Company will continue to focus on maximizing shareholder value during 2000 through debt reduction. In response to industry and market changes, including industry consolidation, the Company considers from time to time additional strategies to enhance shareholder value in light of such changes. These include, among others, strategic alliances and joint ventures; spin-offs; purchase, sale or merger transactions with other large companies; a recapitalization of the Company and other similar transactions. In considering any of these strategies, the Company evaluates the consequences of such strategies including, among other things, the leverage that would result from such a transaction, the tax effects of the transaction, and the accounting consequences of the transaction. In addition, such strategies could have various other significant consequences, including changes in the management, control or operational or acquisition strategies of the Company. There can be no assurance that any one of these strategies will be undertaken, or that, if undertaken, any such strategy will be completed successfully.
Although the Company's deleveraging program was completed during 1999, the Company will continue to evaluate its asset portfolio and may from time to time sell, purchase or trade certain oil and gas properties to focus on its core operating areas and generate additional value. Additionally, the potential exists for gains to be recognized during 2000 related to properties sold in 1999. As some of the major oil and gas industry companies merge, the Company expects some of these companies to divest properties in the Company's core operating areas where it has expertise. The Company hopes to position itself to enable it to purchase some of these properties. The Company is seeking to reduce its capital exposure in the Gomez project by selling or transferring a portion of its working interest. The Company is also planning to sell about $100 million of Canadian assets, certain properties in south Louisiana and its properties in Argentina.
The Company owns a non-operating 50 percent interest in Black Butte, a partnership which operates a surface coal mine complex in southwestern Wyoming. During 1999, Black Butte's sales to its largest customer under a coal supply contract contributed $73.4 million to consolidated operating income. This contract will terminate at the end of 2000. Operating income under the contract is expected to be approximately $71.1 million in 2000. Although Black Butte continues to seek new buyers for its low-sulfur coal, its mining costs are considerably higher than the mining costs of its competition. The Company does not expect to be able to replace the operating income it currently receives under the contract with incremental coal sales after 2000.
During 1998 and 1999, the Company reported tax benefits due to operating losses and tax settlements with governmental agencies and UPC. Additionally, during the fourth quarter 1999, the Company implemented certain available tax management strategies that caused a decrease in current tax liability for 1999. The Company cannot predict with certainty when the tax will be paid.
In connection with the GPM Disposition, the Company entered into a long-term sales agreement with Duke. The long-term sales agreement obligates the Company to sell the majority of its domestic natural gas and existing NGL production to Duke through March 2004. Natural gas volumes dedicated to the agreement
include existing and future production that is available at specific delivery points identified in the agreement. Prices received for the natural gas and NGL production will be tied to current market prices. Additionally, as a result of the agreement, the Company and Duke agreed to keep one another whole on certain gas transportation contracts for up to ten years. The Company will pay Duke if transportation market values fall below the contract transportation rates, while Duke will pay the Company if the market value exceeds the contract transportation rates. The Company established a liability based on the estimated fair value of these firm transportation contracts. The balance of the firm transportation liability at December 31, 1999 was $125.6 million and was included in other current and long-term liabilities on the Consolidated Statement of Financial Position. The Company anticipates payments for the firm transportation liability to be approximately $43.8 million during 2000.
The Company, through one of its affiliates, is a party to a lease agreement ("base lease") for the leveraged lease financing of the Corpus Christi West Plant Refinery ("West Plant") with an initial term expiring December 31, 2003, and successive renewal periods lasting through January 31, 2011. At the conclusion of the initial term of the base lease, any renewal period or January 31, 2011, the Company has the right to purchase the West Plant at the fair market sales value. In connection with the sale by the Company of its refining business in 1987 and 1989, the West Plant was subleased to CITGO Petroleum Corporation ("CITGO") with sublease payments during the initial term equal to the Company's base lease payments and during any renewal period equal to the lesser of the base lease rental, which will be tied to the fair market rental value, or $5 million annually. Additionally, CITGO has the option under the sublease to purchase the West Plant from the Company at the conclusion of the initial term or any renewal term at the fair market sales value, or on January 31, 2011 at a nominal price. If the fair market rental value of the base lease during any renewal term exceeds CITGO's maximum obligation under the sublease, or if CITGO purchases the West Plant on January 31, 2011 and the fair market sales value of the West Plant is greater than the purchase amount specified in the sublease, the Company will be obligated to pay the excess amounts. The Company is unable at this time to determine the fair market rental value or the fair market sales value of the West Plant, but will periodically evaluate the potential of the obligation.
The financial statements of the Company's Canadian subsidiary use the Canadian dollar as its functional currency. Latin American subsidiaries generally use the U.S. dollar as their functional currency. To the extent that business transactions in these countries are not denominated in the functional currency, the Company is exposed to foreign currency exchange rate risk. In addition, in these subsidiaries, certain asset and liability balances are denominated in currencies other than the subsidiary's functional currency. These asset and liability balances must be remeasured in the preparation of the subsidiary financial statements using a combination of current and historical exchange rates, with any resulting remeasurement adjustments included in net income. See "Item 7A.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
The Company has established policies and procedures for managing risk within its organization, including internal controls and governance by a risk management committee. The level of risk assumed by the Company is based on its objectives and earnings, and its capacity to manage risk. Limits are established for each major category of risk, with exposures monitored and managed by Company management and reviewed by the risk management committee.
The Company's primary risk exposure is related to natural gas firm transportation and commodity price risk. During 1999, while hydrocarbon prices were near historic lows and the Company's debt balance was high, the Company entered into hedging arrangements. These hedges were primarily solvency driven in order to shield the Company from losses which may have resulted in a violation of certain debt covenants. As prices recovered in the second half of 1999, the Company experienced higher prices and revenue at the well-head; however, the higher well-head revenue was partially lowered by the $178.1 million in losses associated with the hedge positions that were entered into in early 1999. The lower priced hedges expired at the end of 1999. For 2000, the Company has reduced some of its exposure to lower prices by purchasing puts and fixed price
contracts and has limited some of the upside of higher prices by selling calls and fixed price contracts. In early 2000, the Company hedged slightly more than one-half of its estimated 2000 production with a combination of the fixed price and option hedging strategies.
Below is a more comprehensive and quantitative disclosure of the Company's market risks.
NON-TRADING ACTIVITIES
Commodity Price Risk. The Company uses derivative financial instruments for non-trading purposes in the normal course of business to manage and reduce risks associated with price volatility, contractual commitments and other market variables. The Company's hedging approach is designed to respond to changing market conditions where practicable, while at the same time permitting the evaluation of the need to protect against significant commodity price reductions. These financial instruments usually limit future gains from favorable price movements. The volume of production hedged and the mix of derivative instruments employed are regularly evaluated and adjusted in response to changing market conditions and Company objectives.
Recognition of realized gains/losses and option premium payments/receipts related to non-trading activities is deferred in the Consolidated Statement of Income until the underlying physical product is sold. Unrealized gains/losses are not recorded. Margin deposits, deferred gains/losses and net premiums are included in other current assets or liabilities in the Consolidated Statement of Financial Position. The cash flow impact is reflected in cash flows provided by operations in the Consolidated Statement of Cash Flows.
Utilization of the Company's hedging program may result in the realization on the crude oil and natural gas prices varying from market prices that the Company receives from the sales of crude oil and natural gas. As a result of the hedging programs, revenues in 1999, 1998 and 1997 were $178.1 million, $9 million and $86 million lower, respectively, than if the hedging program had not been in effect. Since these transactions were hedges on production, these impacts were also reflected in the average sales price of the associated products. At December 31, 1999, the Company had margin deposits of $7.4 million and a $26.6 million liability related to recorded hedging losses.
The following table summarizes the Company's open positions as of December 31, 1999 related to equity natural gas and crude oil production. Based on these hedge positions, for each $1.00 increase in the price of a barrel of oil, annualized oil revenues would be reduced by approximately $24.5 million, while for every $0.10 per Mcf increase in the price of natural gas, annualized gas revenues would be lower by approximately $23.1 million.
Unrecognized mark-to-market gains and losses were determined based on current market prices at December 30, 1999, as quoted by recognized dealers, assuming round lot transactions and using a mid-market convention without regard to market liquidity. The actual gains or losses ultimately realized by the Company from such hedges may vary significantly from the foregoing amounts due to the volatility of the commodity markets.
The following table summarizes the Company's closed positions at December 31, 1999 related to the Company's equity natural gas production:
The Company enters into financial contracts in conjunction with its alliance with South Jersey Resources Group (the "Alliance"). The Company has a 50% ownership interest in the Alliance which provides natural gas storage and customer service programs. The following table summarizes the Alliance's open positions as of December 31, 1999:
Firm Transportation Price Risk. The Company was a party to several long-term firm gas transportation agreements that supported the gas marketing program within the GPM business segment which was sold to Duke. Most of the GPM business segment's firm long-term transportation contracts were transferred to Duke in the GPM Disposition. As part of the GPM Disposition, the Company and Duke agreed that the Company will keep Duke whole on certain transportation contracts ("keep-whole agreement"). The Company will pay Duke if transportation market values fall below the contract transportation rates, while Duke agreed to pay the Company if the market value exceeds the contract transportation rates. This keep-whole agreement will be in effect until the earlier of (i) each contract's expiration date, or (ii) March 2009. Transportation contracts transferred to Duke in the GPM Disposition and included in the keep-whole agreement with Duke relate to various pipelines. The significant contracts covered by the keep-whole agreement include: (i) an agreement with Texas Gas Transmission Corporation for a transportation rate of $0.331 per MMBtu for 90 MMBtud of
gas from Carthage, Texas to Lebanon, Ohio expiring October 31, 2008; (ii) an agreement with Pacific Gas Transmission ("PGT") for a transportation rate of $0.328 per MMBtu for 25 MMBtud of gas from Kingsgate, British Columbia to the California/Oregon border expiring October 31, 2023; and (iii) a second agreement with PGT expiring October 31, 2023 for 106 MMBtud of which 47 MMBtud will expire on October 31, 2007. The keep-whole agreement excludes 45 MMBtud of the PGT amount through October 31, 2002 then 20 MMBtud through the end of the contract.
The Company retained a contract with Kern River Gas Transportation Company ("Kern River") which expires on May 31, 2007. Under the transportation agreement, the Company has the right to transport 75 MMcfd of gas on the Kern River system. The current transportation rate is $0.69 per Mcf. This rate can change based on Kern River's cost of service and upon rate regulation policies of the FERC. The Company is a 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 beginning in 2002. As a result of the GPM Disposition, the Company entered into an agreement whereby Duke would operate and handle volume nominations related to the Company's contract with Kern River. Currently, Duke is utilizing the Company's volume transportation rights under the Kern River contract and paying the Company market rates.
The estimated fair value of the firm transportation contracts at December 31, 1999 was a loss of $125.6 million, which is included in other current liabilities and other long-term liabilities on the Consolidated Statement of Financial Position. The Company may adjust its reserve based on changes in current quoted future market rates or estimated long-term rates. Such adjustments could be significant. Management believes its reserves are adequate; however, at December 31, 1999, if the Company had used quoted future market rates at December 31, 1999 to estimate the long-term portion of the reserve discounted at 10%, the Company would have recorded an additional reserve of $41.3 million for the firm transportation commitment period. The estimated fair value of the firm transportation liability is summarized as follows:
TRADING ACTIVITIES
The Company periodically enters into financial contracts in conjunction with market-making or trading activities with the objective of achieving profits through successful anticipation of movements in commodity prices and changes in other market variables. Market-making positions are marked-to-market and gains and losses are immediately included as revenue in the Consolidated Statement of Income. In addition, the fair value of unsettled positions is immediately included in the Consolidated Statement of Financial Position as a current asset or current liability. The activity related to market-making or trading activities did not have a significant effect on the Company's results of operations for the year ended December 31, 1999. At December 31, 1999, the Company's trading activity position did not have a material impact on the results of operations or financial condition of the Company.
INTEREST RATE RISK AND INTEREST RATE SWAPS
The table below summarizes maturities for the Company's fixed-rate and variable-rate debt. Variable rate debt consists of commercial paper and bankers' acceptances that are generally tied to the London Interbank
Offered Rate ("LIBOR"). If interest rates on the Company's variable rate debt increase or decrease by one percentage point, the Company's annual pretax income would decrease or increase by $1.4 million.
The Company periodically enters into rate swaps and contracts to hedge certain interest rate transactions. As of December 31, 1999, the Company had no interest rate swap positions open.
CREDIT RISK
Credit risk is the risk of loss as a result of non-performance by counterparties of their contractual obligations. Because the loss can occur at some point in the future, a potential exposure is added to the current replacement value to arrive at a total expected credit exposure. The Company has established methodologies to determine limits, monitor and report creditworthiness and concentrations of credit to reduce such credit risk. At December 31, 1999, the Company's largest credit risk associated with any single financial counterparty, represented by the net fair value of open contracts, was $7.1 million discounted.
In conjunction with the GPM Disposition, on March 31, 1999, the Company entered into a swap transaction with Duke, which in effect transferred all financial positions held by the GPM business segment to Duke. As a result, the Company has eliminated all price/rate risk related to these positions and is only subject to credit risk for amounts due from Duke or other counterparties under the terms of the swap transactions with Duke or the underlying swap transactions. At December 31, 1999, the Company's credit risk related to these positions was immaterial.
Also in connection with the GPM Disposition, the Company entered into a long-term sales agreement with Duke. The long-term sales agreement obligates the Company to sell the majority of its domestic natural gas and existing NGL production to Duke through March 2004. Prices received will be tied to the current market price for each product. As a result, a significant portion of the Company's credit risk will be with a single customer. Duke is currently considered a good credit risk; however, periodic credit evaluations will continue and be performed more often if circumstances dictate. The agreement with Duke provides for a parental guaranty to cover its obligations under the agreements and the Company has the right to demand a letter of credit and/or other assurances under certain circumstances.
PERFORMANCE RISK
Performance risk results when a financial counterparty fails to fulfill its contractual obligations such as commodity pricing or volume commitments. Typically, such risk obligations are defined within the trading agreements. The Company utilizes its credit risk methodology to manage performance risk.
FOREIGN OPERATIONS RISK
The Company's operations outside of the U.S. are subject to risks inherent in foreign operations, including, without limitation, the loss of revenue, property and equipment from hazards such as expropriation, nationalization, war, insurrection and other political risks, increases in taxes and governmental royalties, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over the Company's international operations. Laws and policies of the U.S. affecting foreign trade and taxation may also adversely affect the Company's international operations.
FOREIGN CURRENCY RISK
The Company's Canadian subsidiary uses the Canadian dollar as its functional currency, and the Latin American subsidiaries use the U.S. dollar as their functional currency. To the extent that business transactions in these countries are not denominated in the respective country's functional currency, the Company is exposed to foreign currency exchange rate risk. In addition, in these subsidiaries, certain asset and liability balances are denominated in currencies other than the subsidiary's functional currency. These asset and liability balances must be remeasured in the preparation of the subsidiary's financial statements using a combination of current and historical exchange rates, with any resulting remeasurement adjustments included in net income.
At December 31, 1999, the Company's Canadian subsidiary had outstanding $650 million of fixed-rate notes and debentures denominated in U.S. dollars. During 1999, the Company recognized a $38.0 million pretax non-cash gain associated with remeasurement of this debt. The potential foreign currency remeasurement impact on earnings from a five-percent change in the year-end Canadian exchange rate would be approximately $32 million.
At December 31, 1999, Latin American subsidiaries had foreign deferred tax liabilities denominated in the local currency, equivalent to $131.6 million in Venezuela and $34.1 million in Guatemala. During 1999, the Company recognized deferred tax benefits of $20.4 million and $8.9 million after tax, respectively, associated with remeasurement of the Venezuelan and Guatemalan deferred tax liabilities. The potential foreign currency remeasurement impact on net earnings from a five percent change in the year-end Latin American exchange rates would be approximately $9 million.
The Company periodically enters into foreign currency contracts to hedge specific currency exposures from commercial transactions. The following table summarizes the Company's open foreign currency positions at December 31, 1999:
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Black Butte Coal Company, A Joint Venture, and R-K Leasing Company Combined Financial Statements as of December 31, 1999 and December 26, 1998, (incorporated herein by reference to Exhibit 99.1 to the Company's Annual Report on Form 10-K for the period ended December 31, 1999).
Black Butte Coal Company, A Joint Venture, and R-K Leasing Company Combined Financial Statements as of December 27, 1997 (incorporated herein by reference to Exhibit 99.2 to the Company's Annual Report on Form 10-K for the period ended December 31, 1999).
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 the 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 the 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 four 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.
George Lindahl III Chairman, President and Chief Executive Officer
Morris B. Smith Vice President, Chief Financial Officer and Treasurer
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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. (a Utah Corporation) and subsidiaries ("the Company") as of December 31, 1999 and 1998, and the related consolidated statements of income and comprehensive income, changes in shareholders' equity and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1999 and 1998, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.
We have also audited the adjustments related to discontinued operations described in Note 3 that were applied to restate the 1997 financial statements. In our opinion, such adjustments are appropriate and have been properly applied.
ARTHUR ANDERSEN LLP
Fort Worth, Texas March 3, 2000
INDEPENDENT AUDITORS' REPORT
To the Board of Directors Union Pacific Resources Group Inc. Fort Worth, Texas
We have audited the accompanying consolidated statements of income, changes in shareholders' equity and cash flows of Union Pacific Resources Group Inc. ("the Company") for the year ended December 31, 1997, (which have been restated and are no longer presented herein). 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 audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the results of its operations and its cash flows for the year ended December 31, 1997 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Fort Worth, Texas January 26, 1998
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
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, 1999 AND 1998
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 YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
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, 1999, 1998 AND 1997
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 AS OF AND FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
GEOGRAPHIC INFORMATION
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(a) 1999, 1998 and 1997 revenues include income from equity affiliates of $78.5 million, $89.7 million and $74.4 million, respectively for the Minerals segment.
(b) Segment operating loss for the Corporate segment consists primarily of general and administrative expense and restructuring charge.
The Company's reportable segments are strategic business units or an aggregation of business units with similar operations and management objectives. The reportable segments are managed separately because each segment requires different operational assets, technology and management strategies.
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. (a Utah Corporation) and subsidiaries (collectively, the "Company"), including its principal operating subsidiary Union Pacific Resources Company ("UPRC"). The Company accounts for investments in affiliated companies (20% to 50% owned) on the equity method of accounting. The Company also consolidates its pro-rata share of oil and gas joint ventures. All significant intercompany transactions are eliminated. The Consolidated Financial Statements for previous periods include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no effect on previously reported net income. Refer to the accompanying notes to the financial statements for additional disclosure of the Company's significant accounting policies.
As a result of the disposition of the Company's gathering, processing and marketing ("GPM") business segment, the GPM business segment has been accounted for as a discontinued operation. GPM results of operations have been excluded from continuing operations in the Consolidated Statements of Income and Cash Flows. GPM net assets have been segregated from continuing operations in the accompanying statements of financial position and reported as net assets of discontinued operations (See Note 3).
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 74).
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. At December 31, 1999 and 1998 hydrocarbon inventory was $13.5 million and $11.0 million, respectively, while materials and supplies inventory was $41.1 million and $53.6 million, respectively.
Oil and Gas Properties. Oil and gas properties are accounted for using the successful efforts method. Under this method, exploration costs (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. Costs to drill exploratory wells that result in additions to reserves are also 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. 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 two to 15 years. Potential impairment of producing properties is assessed annually on a field-by-field basis. Significant unproved properties are not amortized, but are monitored for impairment and assessed annually in detail. Aggregated acquisition costs of individual insignificant unproved properties are amortized from the date of acquisition on a composite basis, which considers past success experience and average lease life (see Note 6).
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Costs of future site restoration, dismantlement and abandonment for producing properties are accrued 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. Additional costs are accrued for offshore and Canadian wells based on internal engineering estimates using the unit of production method with a charge to depreciation, depletion and amortization expense. The balance of the abandonment accrual at December 31, 1999 and 1998 was $75.0 million and $62.1 million, respectively.
Gains or losses on retired, sold or abandoned properties that constitute part of an amortization base are deferred by charging or crediting the investment, net of proceeds, to accumulated depreciation, depletion and amortization unless such non-recognition 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 are recognized in other oil and gas revenues. Gains included in other oil and gas revenues were $148.0 million, $139.9 million and $18.8 million in 1999, 1998 and 1997, respectively. Gains and losses from all other dispositions are recorded in other income.
Goodwill. Intangible and other assets include goodwill of $68.6 million for intangible value acquired from business combinations prior to 1971. Such goodwill is not being amortized because it is considered to have continuing value over an indefinite period. The value of goodwill is evaluated annually to determine whether any potential impairment exists.
Revenue Recognition. Sales from producing wells are recognized on the entitlement method of accounting which defers recognition of sales 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 are recorded to reflect the full net revenue interest. The Company's gas imbalance liability at December 31, 1999 and 1998 was $5.5 million and $5.2 million, respectively. Natural gas and crude oil marketing revenue is included in other oil and gas revenue and recorded net of the cost of product purchased.
Recently issued accounting standards. The Financial Accounting Standards Board ("FASB") has issued Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," and SFAS No. 137, which defers the effective date of SFAS No. 133 to fiscal years beginning after June 15, 2000. SFAS No. 133 requires that all derivatives be recognized on the balance sheet and measured at fair value. If certain conditions are met, a derivative may be specifically designated as a hedge and be eligible for special accounting treatment. However, the special accounting treatment afforded hedge transactions may delay the recognition of a portion of the gain or loss on the derivative, which would later be recorded concurrent with the gain or loss on the item being hedged. For derivatives not designated as hedges, gains or losses are recognized in earnings in the period of change. The impact of the statement on the Company will depend upon price volatility and the level of open derivative positions at the end of a reporting period. The Company plans to adopt SFAS No. 133 for the first quarter 2001 and is currently evaluating the effects of this pronouncement. Adoption will require the Company to begin recording unrealized gains and losses in the Consolidated Statement of Financial Position and in the Consolidated Statement of Comprehensive Income.
1. NATURE OF OPERATIONS
The Company is an independent oil and gas company engaged primarily in the exploration for and the development and production of natural gas and crude oil in several major basins in the United States, Canada, Guatemala, Venezuela and other international areas. The Company markets all of its crude oil production together with significant volumes of crude oil produced by others. In 1998, the Company marketed a substantial portion of its natural gas and natural gas liquids ("NGLs"); however, in 1999 the Company entered into a long-term natural gas sales agreement to sell a substantial portion of its domestic natural gas and NGLs to Duke (hereinafter defined) (see Notes 3 and 5). The Company also engages in the hard UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
minerals business through non-operated joint ventures and royalty arrangements in several coal, trona (natural soda ash) and industrial mineral 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 crude oil and natural gas, the price of foreign imports, the level of consumer demand and the price and availability of alternative fuels. The Company manages a portion of the operating risk relating to hydrocarbon price volatility through hedging activities (see Note 5).
2. ACQUISITIONS
Norcen Energy Resources Limited. On January 25, 1998, the Company and Union Pacific Resources Inc. ("UPRI"), an Alberta corporation and a wholly-owned subsidiary of the Company, entered into a pre-acquisition agreement ("Pre-acquisition Agreement") with Norcen Energy Resources Limited ("Norcen"). Under the Pre-acquisition Agreement, the Company and UPRI agreed to make an offer (the "Tender Offer") for up to 100% of the common shares of Norcen, subject to certain conditions. On March 3, 1998, the Company announced the closing of the Tender Offer. In total, 95.5% of the outstanding common shares of Norcen were tendered at a purchase price of U.S. $13.65 per share.
On March 5, 1998, the Company and UPRI completed the compulsory acquisition of the remaining common shares outstanding which were not tendered. (The closing of the Tender Offer and completion of the compulsory acquisition is referred to as the "Norcen Acquisition.") The aggregate cash purchase price for the Norcen Acquisition, including non-recurring transaction costs of $28.1 million, was $2.634 billion. In addition, UPRI assumed the long-term debt obligations of Norcen.
Norcen operations primarily consisted of crude oil and natural gas exploration and development operations in western Canada, the Gulf of Mexico, Guatemala and Venezuela.
The Company funded the purchase price of the Norcen Acquisition through the issuance of commercial paper, supported by a U.S. $2.7 billion 364-Day Competitive Advance/Revolving Credit Agreement dated March 2, 1998. In accordance with Accounting Principles Board Opinion No. 16, "Business Combinations," the Norcen Acquisition was accounted for as a purchase effective March 3, 1998.
The following table represents the allocation of the total purchase price of the assets acquired and liabilities assumed, based upon their fair values on the date of the Norcen Acquisition and pushed down to the acquired Company. In accordance with SFAS No. 109 "Accounting for Income Taxes", a deferred tax liability was recognized for the differences between the allocated values and the tax bases of the acquired assets and liabilities.
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table presents unaudited pro forma Condensed Consolidated Statements of Income of the Company for the twelve months ended December 31, 1998 and 1997, as though the Norcen Acquisition had occurred on January 1, 1997. Certain adjustments were made to the financial information to conform to the accounting policies and financial statement presentation of the Company.
The unaudited pro forma condensed consolidated information presented above is not necessarily indicative of the results of operations which would have occurred had the Norcen Acquisition been consummated on January 1, 1997, nor is it necessarily indicative of future results of operations.
Norcen Summarized Financial Information. As a result of the Norcen Acquisition, and the amalgamation of Norcen with UPRI, UPRI assumed the obligations of Norcen, including the public debt obligations of Norcen (the "Debt Securities"). The Debt Securities include 6.8% Debentures due July 2, 2002, in the aggregate principal amount of $250 million, 7 3/8% Debentures due May 15, 2006, in the aggregate principal amount of $250 million, and 7.8% Debentures due July 2, 2008, in the aggregate principal amount of $150 million, each of which have been fully and unconditionally guaranteed by the Company.
The following table presents summarized financial information for UPRI (as successor to Norcen) as of and for the year ended December 31, 1999 and the two months ended February 28, 1998, and ten months ended December 31, 1998. This summarized financial information is being provided pursuant to Section G of Topic 1 of Staff Accounting Bulletin No. 53 -- "Financial Statement Requirements in Filings Involving the Guarantee of Securities by a Parent." The Company will continue to provide such summarized financial information for UPRI as long as the Debt Securities remain outstanding.
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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(a) Results for UPRI as of and for the ten months ended December 31, 1998, include adjustments to reflect U.S. GAAP and the successful efforts method of accounting. Adjustments to reflect the application of the purchase method of accounting for the Norcen Acquisition are included effective March 3, 1998.
(b) Results for Norcen as of and for the two months ended February 28, 1998 have not been restated in accordance with U.S. generally accepted accounting principles ("GAAP") and reflect the full cost method of accounting for oil and gas operations.
(c) Results reflect the impairment and write-down of certain oil and gas properties.
(d) Net loss includes $40 million in costs incurred by Norcen in connection with the Norcen Acquisition which were not reimbursed by the Company.
3. DIVESTITURES
Deleveraging Program. In 1998, the Company commenced a deleveraging program which was designed to reduce the Company's debt. The deleveraging program, which was initiated following the completion of the Norcen Acquisition, included the sale of non-strategic properties and assets. The completed sales undertaken as part of the Company's deleveraging program include the following:
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(a) As a result of the sale of the South Texas Package, the Company recorded a fully reserved $20.6 million note receivable included in other current assets. If the note is collected, the Company will record $20.6 million in additional proceeds and gain on the South Texas sale.
Discontinued Operations. In November 1998, the Company entered into a Merger and Purchase Agreement ("Agreement") with Duke Energy Field Services, Inc. ("Duke") to sell its GPM business segment for $1.36 billion in cash. On March 31, 1999, the Company closed on the sale (the "GPM
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Disposition"). The GPM Disposition consisted primarily of the Company's pipelines, gathering systems, natural gas processing plants and natural gas and NGL marketing assets and operations. These operations included interests in nineteen natural gas processing plants (together with approximately 7,200 miles of pipelines that support these processing plants), as well as two non-operated NGL fractionation plants. The Company retained its crude oil marketing business. The Company recorded a $157.0 million after-tax gain on the GPM Disposition, including $108.3 million for accrued taxes payable.
Summarized information relating to discontinued results of operations, excluding the after-tax gain on the GPM Disposition are as follows:
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(a) The Company allocated interest expense to the GPM business segment based on the ratio of net assets of discontinued operations to total Company net assets, excluding $3.6 billion of debt associated with the Norcen Acquisition.
Summarized information relating to net assets of discontinued operations are as follows:
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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(a) In June 1998, the Company entered into a third-party forward sales arrangement covering a total of 567 MMcf of gas per day. At the time of the arrangement, the Company received $250 million and became obligated to deliver gas from October 1998 through March 1999. The Company recorded the obligation associated with this transaction as an advance payment included in net assets of discontinued operations. This current liability was amortized and recorded on the Consolidated Statement of Income as part of discontinued operations, as the gas was delivered over the remaining term of the contract.
4. RESTRUCTURING CHARGES
During the first quarter of 1999, the Company reorganized its operating groups, announced workforce reductions for its Canadian and U.S. operations and established an early retirement program. As a result of these actions, the Company recorded a $14.5 million restructuring charge. The charge included $7.3 million for severance costs and excess office space commitments, an additional $4.2 million liability for pension and other postretirement benefits in connection with the early retirement program and a $3.0 million valuation allowance for specialty drilling equipment and supplies no longer required for cancelled drilling programs. Payments of $7.2 million were made for severance and office lease costs. The pension and other postretirement liabilities are included in the balance of the Company's liabilities for those items (see Note 11). The valuation allowance for specialty drilling equipment and supplies was recorded to the inventory accounts.
During 1998, the Company announced a workforce reduction for its domestic operations and implemented programs to reduce overhead and other costs. The $17.0 million restructuring charge included $7.6 million for workforce reductions of approximately 140 U.S. employees, $5.0 million for a drilling rig commitment and $4.4 million for excess office space commitments. At December 31, 1998, $14.6 million of the reserve remained. During 1999, net payments of $8.1 million were made and $3.1 million of the rig commitment charge was reversed as a result of favorable settlement negotiations. At December 31, 1999, the $3.4 million remaining reserve represents excess office space commitments net of sublease rentals.
5. FINANCIAL INSTRUMENTS
Hedging. The Company has established policies and procedures for managing risk within its organization, including internal controls and governance by a risk management committee. The level of risk assumed by the Company is based on its objectives and earnings, and its capacity to manage risk. Limits are established for each major category of risk, with exposures monitored and managed by Company management and reviewed semi-annually by the risk management committee. Major categories of the Company's risk are defined as follows:
Commodity Price Risk -- Non-Trading Activities. The Company uses derivative financial instruments for non-trading purposes in the normal course of business to manage and reduce risks associated with contractual commitments, price volatility and other market variables. These instruments are generally put in place to limit risk of adverse price movements; however, these same instruments usually limit future gains from favorable price movements. Risk management activities are generally accomplished pursuant to exchange-traded contracts or over-the-counter swaps and options.
Recognition of realized gains/losses and option premium payments/receipts relating to non-trading activities are deferred in the Consolidated Statement of Income until the underlying physical product is sold. Unrealized gains/losses are not recorded. Margin deposits, deferred gains/losses and net premiums are included in other current assets or liabilities in the Consolidated Statement of Financial Position. The cash flow impact is reflected in cash flows provided by operations in the Consolidated Statement of Cash Flows.
Utilization of the Company's hedging program may result in crude oil and natural gas prices varying from market prices. As a result of the hedging program, revenues in 1999, 1998 and 1997 were $178.1 million, $9 million and $86 million lower, respectively than if the hedging program had not been in effect. Since these transactions were hedges on production, these impacts were also reflected in the average sales price of the associated products.
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Commodity Price Risk -- Trading Activities. The Company periodically enters into financial contracts in conjunction with market-making or trading activities with the objective of achieving profits through successful anticipation of movements in commodity prices and changes in other market variables. Market- making positions are marked-to-market and gains and losses are immediately included as revenue in the Consolidated Statement of Income. In addition, the fair value of unsettled positions is immediately included in the Consolidated Statement of Financial Position as a current asset or current liability. As of December 31, 1999 and 1998, there were no transactions in place which would materially affect the results of operations or financial condition of the Company.
Interest Rate Swaps. The Company periodically enters into rate swaps and contracts to hedge certain interest rate transactions. As of December 31, 1999 and 1998, there were no interest rate contracts outstanding which would materially affect the results of operations or financial condition of the Company. During 1998, the Company entered into rate lock contracts to hedge interest rates related to a contemplated bond issuance. The bonds were not issued and the Company recognized a $14.3 million pre-tax loss in 1998 associated with these contracts.
Foreign Currency. The financial statements of foreign subsidiaries, except those subsidiaries located in countries which have highly inflationary economies, utilize the local currency as their functional currency. The financial statements of foreign subsidiaries located in countries which have highly inflationary economies utilize the U.S. dollar as their functional currency. Monetary assets and liabilities denominated in a currency other than the functional currency are remeasured into the functional currency with the corresponding gains/ losses included in the Consolidated Statement of Income. The financial statements of those foreign subsidiaries which do not utilize the U.S. dollar as their functional currency are translated into the U.S. dollar. Assets and liabilities are translated at the current exchange rate, while revenues and expenses are translated at the average exchange rate for the reporting period. Translation gains/losses are not included in the Consolidated Statement of Income but are recorded in a separate section of shareholders' equity. The Company's Canadian subsidiary's functional currency is the Canadian dollar. Generally, the functional currency of the Company's other foreign subsidiaries is the U.S. dollar.
At December 31, 1999, the Company's Canadian subsidiary had outstanding $650 million of fixed-rate notes and debentures denominated in U.S. dollars. During 1999, the Company recognized a $38.0 million pretax non-cash gain associated with remeasurement of this debt and a $46.5 million pretax non-cash loss during 1998. The potential foreign currency remeasurement impact on earnings from a five percent change in the year-end Canadian exchange rate would be approximately $32 million.
Two of the Company's Latin American subsidiaries had foreign deferred tax liabilities denominated in the local currency. At December 31, 1999 and 1998, Venezuela had a $131.6 million and $159.6 million liability, respectively and Guatemala had a $34.1 million and $58.0 million liability, respectively. During 1999 and 1998, the Company recognized after-tax deferred tax benefits associated with the remeasurement of the deferred tax liabilities of $20.4 million and $15.2 million in Venezuela, and $8.9 million and $7.3 million in Guatemala, respectively. The potential foreign currency remeasurement impact on net earnings from a five percent change in the year-end Latin American exchange rates would be approximately $9 million.
The Company may periodically enter into foreign currency contracts to hedge specific currency exposures from commercial transactions. As a result of the Norcen Acquisition, the Company acquired foreign currency forward exchange contracts with maturities through October 2000, and recorded a $15.5 million deferred liability representing the fair value of these contracts. These contracts were deemed to be hedges of UPRI's future U.S. dollar denominated hydrocarbon sales. This deferred liability will be amortized over the contract terms. The unrecognized loss on foreign currency contracts at December 31, 1999, excluding the $1.4 million remaining unamortized deferred liability, was $2.9 million.
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Concentrations of Credit Risk. Credit risk is the risk of loss as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. Because the loss can occur at some point in the future, a potential exposure is added to the current replacement value to arrive at a total expected credit exposure. The Company has established methodologies to establish limits, monitor and report creditworthiness and concentrations of credit to reduce such credit risk. At December 31, 1999, the Company's largest credit risk associated with any single counterparty, represented by the net fair value of open contracts with such counterparty, was $7.1 million.
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. The Company derives a substantial portion of its revenues from international operations in Canada and Latin America. With the exception of one large customer, described below, 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.
In connection with the GPM Disposition, the Company entered into a long-term sales agreement with Duke. The long-term sales agreement obligates the Company to sell the majority of its domestic natural gas and existing NGL production to Duke through March 2004. Prices received for the natural gas and NGLs will be tied to the current market price for each product. As a result, a significant portion of the Company's credit risk will be with a single customer. Duke is currently considered a good credit risk; however, periodic credit evaluations will continue and will be performed more often if circumstances dictate. The agreement with Duke provides for a parental guaranty to cover its obligations under the agreements and the Company has the right to demand a letter of credit and/or other assurances under certain circumstances. During 1999, sales to Duke accounted for 31% of the Company's consolidated revenues and 38% of United States revenues. Approximately 25% of the Company's trade receivables outstanding at December 31, 1999 were due from Duke which exposes the Company to a concentration of credit risk.
Performance Risk. Performance risk results when a counterparty fails to fulfill its contractual obligations with respect to commodity pricing or volume commitments. Typically, such risk obligations are defined within the trading agreements. The Company utilizes its credit risk methodology to manage performance risk.
6. PROPERTIES
Major property classifications were as follows:
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Accumulated depreciation, depletion and amortization by major property classifications were as follows:
Based upon the Company's analysis of expected future net cash flows from its crude oil and natural gas properties, certain properties were deemed to be impaired due to lower hydrocarbon prices and/or downward revisions in reserve estimates. As a result of its analysis, the Company adjusted the net book value of such properties to their fair value with a charge to depreciation, depletion and amortization of $70.6 million in 1999 for exploration and production properties primarily located in the U.S. Onshore area and uranium properties. During 1998, the Company adjusted the net book value of properties with a $1.2 billion charge, primarily on properties acquired in the Norcen Acquisition. Fixed asset additions included capitalized interest of $0.4 million and $0.9 million in 1999 and 1998, respectively.
7. CAPITAL AND EXPLORATORY EXPENDITURES
Capital and exploratory expenditures include the following:
8. INCOME TAXES
Deferred taxes are established for all temporary differences between the book and tax bases of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that will be in effect in the years in which the temporary differences are expected to reverse. Non-U.S. subsidiaries compute taxes at rates in effect in the various countries. Earnings of these subsidiaries may also be subject to additional income and withholding taxes when they are distributed as dividends. Deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested by the local subsidiaries and thus not considered available for distribution to the parent Company. The Company has undistributed earnings of its 100% owned foreign subsidiaries that arose in 1999 and prior years.
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Income (loss) from continuing operations before taxes is as follows:
Components of income tax expense (benefit), from continuing operations, were as follows:
Deferred tax liabilities (assets), were as follows:
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A reconciliation between U.S. statutory and consolidated effective tax rates is as follows:
The Company generates Section 29 tax credits from the sale of certain fuels produced from non-conventional 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 must be sold before January 1, 2003. The Company generated $17.9 million, $16.4 million and $18.8 million of Section 29 tax credits in 1999, 1998 and 1997, respectively. The Federal tax law provides for the use of these credits against regular Federal income tax liability. Accordingly, the Company utilized $6.9 million of Section 29 tax credits on its 1998 tax return. It is anticipated that all of the 1999 Section 29 tax credits along with some of the prior year credits will be recognized in the Company's 1999 tax return. The Company recognized favorable tax adjustments relating to prior year Federal tax returns in the amount of $17.4 million for 1999 and $4 million for 1998.
While the operations of the Company in Guatemala are subject to local income taxes, no liability has arisen in recent years since sufficient unrecovered costs, carried forward from previous years, have been available to offset current taxable income. Guatemalan tax benefits, which can be carried forward indefinitely, were $57.6 million at December 31, 1999. Other domestic subsidiary net operating losses in existence at the time of the Norcen Acquisition were merged with the Company when those subsidiaries were dissolved. The Company plans to utilize the losses in 2000 or a future year.
On September 1, 1999, the Company and its former parent, Union Pacific Corporation ("UPC"), settled certain outstanding issues pertaining to the allocation of all Federal and state tax liabilities, including interest, for the tax years 1968 through 1982. This settlement was made pursuant to the Tax Allocation Agreement entered into as of October 6, 1995, between the Company and UPC. This settlement resulted in the receipt by the Company from UPC on September 3, 1999, of $29 million (including $20.5 million of interest income recorded in other income) in full and final settlement of all amounts owed to or by UPR with respect to tax years 1968 through 1982. The tax settlement with UPC enabled the Company to reevaluate its deferred tax reserves, and as a result, the Company recorded $11.9 million of deferred tax benefits related to the tax years covered by the settlement. The Company and UPC also agreed to suspend settlement rights under the Tax Allocation Agreement with respect to post-1982 tax years until July 1, 2001. UPC has informed the Company that all material deficiencies prior to 1986 have been settled with the Internal Revenue Service ("IRS"). UPC is negotiating with the IRS Appeals Office concerning 1986 through 1989. The IRS has completed its examination of the Company's returns for 1990 through 1994; however, their audit remains open until resolution of the UPC issues. The IRS has initiated steps to begin the process of examining the Company's
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records for 1995 through 1998. The Company believes it has adequately provided for Federal and state income taxes.
In 1997, Norcen received a reassessment from Canadian tax authorities in the amount of $81.1 million concerning the deductibility of certain expenses and foreign exchange losses claimed for income tax purposes during the period 1989 through 1993. In spite of Norcen's disagreement and appeal, the reassessment was fully funded in 1997. As a result of the Norcen Acquisition, the Company valued this issue at $17.0 million, net of any valuation allowance, as part of the purchase price allocation. On March 8, 1999, UPRI entered into an agreement with Canadian tax authorities to settle these claims out of court. Under the terms of the settlement, the Company received a refund of approximately $54.6 million dollars. The Company recorded $7.1 million of interest to other income and a $27.9 million deferred income tax benefit related to the refund.
9. DEBT
The total debt of the Company is summarized below:
At year-end 1998, the Company had three debt facilities totaling an aggregate of U.S. $2.5 billion. These facilities were comprised of a $1.0 billion 364-Day Competitive Advance/Revolving Credit Agreement (the "Bridge Facility"), a $750 million 364-Day Competitive Advance/Revolving Credit Agreement and a $750 million Competitive Advance/Revolving Credit Agreement ("Long-Term Facility") expiring in October 2003.
In April 1999, the Company issued $500 million of notes and debentures comprised of $200 million 7.3% Notes due April 2009 and the $300 million 7.95% Debentures due April 2029. The notes and debentures were issued under the Company's existing $1.0 billion shelf registration statement, of which $500 million remains available.
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During the first half of 1999, commercial paper, supported in part by the Company's Bridge Facility, was repaid using proceeds from property sales, proceeds from the sale of the GPM business segment and the issuance of the long-term notes and debentures. The Bridge Facility was terminated in April 1999. The $750 million 364-Day Competitive Advance/Revolving Credit Agreement expired in October 1999, leaving the Company with the Long-Term Facility at year-end 1999. The Long-Term Facility contains a covenant stipulating that the ratio of consolidated debt to consolidated EBITDAX -- the sum of operating income (before adjustments for income taxes, interest expense or extraordinary gains or losses), depreciation, depletion and amortization and exploration expenses -- cannot exceed 3.25:1.00. The Long-Term Facility also places other restrictions on the Company regarding the creation of liens, incurrence of additional indebtedness by subsidiaries, transactions with affiliates, sales of stock of Union Pacific Resources Company (a wholly-owned subsidiary of the Company) and certain mergers, consolidations and asset sales. The Company was in compliance with the covenant provisions at year-end 1999 and 1998.
The 2005, 2008 and 2009 notes and the 2018, 2028 and 2029 debentures are redeemable as a whole or in part, at the option of the Company at any time. The redemption price is equal to the greater of (i) 100% of the principal amount of the Debt Securities to be redeemed or (ii) the sum of the present values of the remaining scheduled payments thereon, discounted to the redemption date on a semi-annual basis at the Treasury Rate, plus a stated basis point spread and accrued interest on the principal amount being redeemed to the redemption date. There are no other notes or debentures redeemable prior to maturity. None of the Company's notes and debentures are subject to a sinking fund requirement. At December 31, 1999, the Company had an effective shelf registration statement on file with the Securities and Exchange Commission that would permit the Company or certain identified subsidiaries to offer up to $500 million in debt, equity and/or other securities.
During 1999, the Company purchased on the open market and retired long-term debt with a face value of $94.5 million at a discount prior to maturity. The retirement of long-term debt due to the repurchases resulted in an extraordinary gain of $3.4 million, net of $1.8 million of tax. The gain on the retirement was classified as a gain from an extraordinary item on the Consolidated Statement of Income.
At December 31, 1999, $135.1 million of commercial paper and bankers acceptances was classified as long-term. This classification reflects the Company's intent and ability to maintain these borrowings on a long-term basis, supported by the Long-Term Facility through the issuance of additional commercial paper and/or new term financings. Debt maturities through 2004, excluding capital leases, are $135.1 million of bankers acceptances due in 2000 and $250 million of Debentures due July 2, 2002.
The fair value of the Company's long-term debt, excluding commercial paper and bankers acceptances, debt discount/premium and capital lease obligations was $2,467 million at December 31, 1999 and $2,088 million at December 31, 1998. The fair value was estimated using quoted market prices. These fair values were trading at a discount to the face value of 93.8% at both December 31, 1999 and 1998.
As a result of the Norcen Acquisition, the Company recorded a $31.5 million debt premium, representing the excess of the fair value over the carrying value of the debt acquired. The $25.2 million remaining debt premium, net of $7.2 million in debt discount related to prior debt issuances, are being amortized over the life of the debt term.
The Company has guaranteed a portion of the OCI Wyoming, L.P debt facility. At December 31, 1999, OCI Wyoming, L.P. had an outstanding debt facility balance of $30 million, of which the Company has guaranteed $14.7 million. The Company's portion of the debt is reflected in the balance for investment in affiliate on the Consolidated Statement of Financial Position.
The Company utilizes letters of credit to support certain financing instruments, performance contracts and insurance policies. The fair value of the letters of credit at December 31, 1999 and 1998 was $41.3 million and $58.6 million, respectively. UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. LEASE COMMITMENTS
The Company leases several office buildings, certain production platforms and other property under operating leases. The Company also maintains a capital lease for furniture and walls in its Fort Worth offices. Future minimum lease payments for operating and capital leases with initial non-cancelable lease terms in excess of one year as of December 31, 1999, were as follows:
Rent expense, net of sublease income, for operating leases with terms exceeding one month was $60.2 million in 1999, $59.8 million in 1998, and $19.2 million in 1997. Sublease income for the next five years will be $30.5 million in 2000, $29.8 million in 2001, $29.8 million in 2002, $28.5 million in 2003 and $0.4 million in 2004. Capital leases included in corporate fixed assets were $17.4 million and $18.1 million at December 31, 1998 and 1999, respectively.
11. RETIREMENT PLANS
The Company provides pension, health care and life insurance benefits to all eligible retirees in the U.S. and pension benefits to all eligible retirees in Canada. No such pension or other benefits are provided to employees of other foreign subsidiaries.
U.S. Pension Benefits. Pension benefits for U.S. employees are based on years of service and compensation during the last years of employment. Contributions to the plans are calculated on the Projected Unit Credit actuarial funding method and are not less than the minimum funding standards set forth in the Employees Retirement Income Security Act of 1974, as amended. The portion of the funded plan's assets held in fixed-income and short-term securities was approximately 33% and 32% as of December 31, 1999 and 1998, respectively, with the remainder primarily in equity securities.
Curtailments and Termination of Benefits. During 1999, the Company announced reductions in force, a voluntary retirement incentive program ("VRIP") and the sale of the GPM business segment. The separations due to these programs triggered curtailment accounting and termination benefit accounting as a result of the VRIP. The Company recognized curtailment gains of $11.4 million, offset by costs of the termination of benefits of $10.5 million. These separations caused a slight reduction in the Company's retiree benefits obligations due to reduced expected future benefits for the employees affected by these programs.
Other U.S. Postretirement Benefits. Postretirement health and life insurance benefits are provided to all eligible U.S. retirees. The Company does not currently pre-fund health care and life insurance benefit costs.
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Canadian Pension Benefits. Benefits provided under the Canadian defined benefit plan are based on years of service and highest compensation over a specified number of consecutive years. The provisions under the defined benefit plan were modified to provide employees with a defined contribution plan option, which has been retroactively elected by substantially all active employees. Under the defined contribution plan, the Company matches a stated percentage of employee contributions to the plan. Both the defined benefit payments and the defined contribution Company match obligation are paid from assets held in trust. The Company will make contributions to the plans, if necessary, to maintain adequate assets in trust. Contributions are not expected to be necessary for several years.
The following pension credits and funded status are based on historical actuarial valuations.
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(a) Represents payments relating to unfunded plans. In addition, the Company periodically settles a portion of the unfunded supplemental pension plan benefit obligations through the purchase of annuities.
(b) $0.9 million and $0.8 million of Canadian pension benefits paid in 1999 and 1998 respectively, represent payments to fund the defined contribution Company match.
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For measurement purposes, a 7.2% annual rate of increase in the per capita cost of covered health care benefits was assumed for 1999. The rate was assumed to gradually decrease to 5% in 2005 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts reported for the postretirement benefit plan. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
12. ENVIRONMENTAL EXPOSURE
Environmental expenditures related to treatment or cleanup are expensed when incurred, while environmental expenditures which extend the life of the property or prevent future contamination are capitalized in accordance with generally accepted accounting principles. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated, based on
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current law and existing technologies. Environmental accruals are recorded at undiscounted amounts and exclude claims for recoveries from insurance or other third parties.
The Company generates and disposes of hazardous and non-hazardous waste in its current operations as well as formerly owned operations and is subject to increasingly stringent Federal, state, local, provincial and international environmental regulations. The Company has identified seven 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 violation 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.
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. 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, a provision of $50.5 million for future environmental costs and $55.0 million for future site preparation costs was established ($87.8 million in total remaining at December 31, 1999) and is categorized as other current liabilities and long-term liabilities (see Note 14).
As of December 31, 1999 and 1998, liabilities totaling $65.2 million and $74.7 million, respectively, 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 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 $34.1 million for the obligation to participate in the remediation of the Wilmington field properties. 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 liabilities. 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.
Anticipated payments of environmental liabilities at December 31, 1999, which will be funded by cash generated by operations, are as follows:
The Company also is involved in reducing emissions, spills and migration of hazardous materials. Remediation of identified sites and control of environmental exposures required spending of $11.6 million in 1999 and $17.0 million in 1998. In 2000, the Company anticipates spending a total of $19 million for remediation, control and prevention. Based on current rules and regulations, management does not expect
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future environmental obligations to have a material impact on the results of operations, cash flows or financial condition of the Company.
13. COMMITMENTS AND CONTINGENCIES
The Company was a party to several long-term firm gas transportation agreements that supported the gas marketing program within the GPM business segment which was sold to Duke. Most of the GPM business segment's firm long-term transportation contracts were transferred to Duke in the GPM Disposition. As part of the GPM Disposition, the Company and Duke agreed that the Company will keep Duke whole on certain transportation contracts ("keep-whole agreement"). The Company will pay Duke if transportation market values fall below the contract transportation rates, while Duke agreed to pay the Company if the market value exceeds the contract transportation rates. This keep-whole agreement will be in effect until the earlier of (i) each contract's expiration date, or (ii) March 2009. Transportation contracts transferred to Duke in the GPM Disposition and included in the keep-whole agreement with Duke relate to various pipelines. The significant contracts covered by the keep-whole agreement include: (i) an agreement with Texas Gas Transmission Corporation for a transportation rate of $0.331 per MMBtu for 90 MMBtud of gas from Carthage, Texas to Lebanon, Ohio expiring October 31, 2008; (ii) an agreement with Pacific Gas Transmission ("PGT") for a transportation rate of $0.328 per MMBtu for 25 MMBtud of gas from Kingsgate, British Columbia to the California/Oregon border expiring October 31, 2023; and (iii) a second agreement with PGT expiring October 31, 2023 for 106 MMBtud of which 47 MMBtud will expire on October 31, 2007. The keep-whole agreement excludes 45 MMBtud of the PGT amount through October 31, 2002 then 20 MMBtud through the end of the contract.
The Company retained a contract with Kern River Gas Transportation Company ("Kern River") which expires on May 31, 2007. Under the transportation agreement, the Company has the right to transport 75 MMcfd of gas on the Kern River system. The current transportation rate is $0.69 per Mcf. This rate can change based on Kern River's cost of service and upon rate regulation policies of the FERC. The Company is a 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 beginning in 2002. As a result of the GPM Disposition, the Company entered into an agreement whereby Duke would operate and handle volume nominations related to the Company's contract with Kern River. Currently, Duke is utilizing the Company's volume transportation rights under the Kern River contract and paying the Company market rates.
Included in the Consolidated Statements of Financial Position of the Company is a reserve for the estimated fair value of the difference between the total rate under the firm transportation agreements and estimated market rates through March 2009. The reserve, which is included in other current liabilities and other long-term liabilities, was $43.8 million and $81.8 million at December 31, 1999 and $17.5 million and $71.2 million at December 31, 1998, respectively. The Company may adjust its reserve based on changes in current quoted future market rates or estimated long-term rates. Such adjustments could be significant. Management believes its reserves are adequate; however, at December 31, 1999, if the Company had used quoted future market rates at December 31, 1999 to estimate the long-term portion of the reserve discounted at 10%, the Company would have recorded an additional reserve of $41.3 million for the firm transportation commitment period.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Anticipated discounted and undiscounted payments for firm transportation commitment at December 31, 1999, which will be funded by cash generated by operations, are as follows:
In February 2000, the Company entered into a $70 million contract with Noble Drilling (U.S.) Inc. for the services of a semisubmersible drilling rig designed for operations in water depths up to 5,000 feet. Under this agreement, the Company has a commitment to use the rig for 15 months over a five-year period commencing January 1, 2000.
In connection with the disposition of significant pipeline, refining and producing property assets, the Company has made certain representations and warranties relating to the assets sold (covering, among other matters, the condition and capabilities of certain assets and compliance with environmental and other laws) and provided certain indemnities with respect to liabilities associated with such assets. The Company has been advised of possible claims which may be asserted by the purchasers of certain disposed assets for alleged breaches of representations and warranties and under certain indemnities. 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 ultimate outcome of these claims, the Company does not expect these matters to have a material adverse effect on its results of operations, cash flows or consolidated financial condition.
The Company, through one of its affiliates, is a party to a lease agreement ("base lease") for the leveraged lease financing of the Corpus Christi West Plant Refinery ("West Plant") with an initial term expiring December 31, 2003, and successive renewal periods lasting through January 31, 2011. At the conclusion of the initial term of the base lease, any renewal period or January 31, 2011, the Company has the right to purchase the West Plant at the fair market sales value. In connection with the sale by the Company of its refining business in 1987 and 1989, the West Plant was subleased to CITGO Petroleum Corporation ("CITGO") with sublease payments during the initial term equal to the Company's base lease payments and during any renewal period equal to the lesser of the base lease rental, which will be tied to the fair market rental value, or $5 million annually. Additionally, CITGO has the option under the sublease to purchase the West Plant from the Company at the conclusion of the initial term or any renewal term at the fair market sales value, or on January 31, 2011 at a nominal price. If the fair market rental value of the base lease during any renewal term exceeds CITGO's maximum obligation under the sublease, or if CITGO purchases the West Plant on January 31, 2011 and the fair market sales value of the West Plant is greater than the purchase amount specified in the sublease, the Company will be obligated to pay the excess amounts. The Company is unable at this time to determine the fair market rental value or the fair market sales value of the West Plant, but will periodically evaluate the potential effect of the obligation.
There are lawsuits pending against the Company and certain of its subsidiaries which are described in Part I, Item 3 -- "Legal Proceedings" in this Annual Report on Form 10-K. The Company intends to defend vigorously against these lawsuits as well as any similar lawsuits. In the opinion of management of the
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Company, the outcome of these matters should not have a materially adverse effect on results of operations, cash flows or consolidated financial condition.
The Company is a defendant in a number of lawsuits and is involved in governmental proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. The Company has also been named as a defendant in various personal injury claims, including numerous claims by employees of third party contractors alleging exposure to asbestos and asbestos-containing materials while working at the Corpus Christi refinery, which the Company sold in segments in 1987 and 1989. While the Company's management cannot predict the outcome of such litigation and other proceedings, management does not expect these matters to have a materially adverse effect on the consolidated results of operations, financial condition or cash flows of the Company.
14. OTHER CURRENT AND LONG-TERM LIABILITIES
Other current liabilities include the following:
Other long-term liabilities include the following:
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(a) Black Butte
The Company has a 50% ownership interest in Black Butte Coal Company and R-K Leasing Company ("Black Butte"), partnerships which operate a surface coal mine complex in southwestern Wyoming. The
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Company accounts for these partnerships under the equity method of accounting. Summarized financial information for Black Butte is as follows:
During 1999 and 1998, Black Butte's sales to its largest customer under a coal supply contract accounted for $73.4 million and $79.3 million of the Company's consolidated operating income, respectively. This coal supply contract will terminate by the end of 2000. 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 currently received under the contract with incremental coal sales after 2000.
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, 1999 and 1998 were $54.6 million and $52.0 million, respectively, of which the Company's share is $27.3 million and $26 million, respectively. Anticipated cash expenditures for this reclamation liability are expected to be incurred in years beginning after 2004.
A supplier of coal to Black Butte has been assessed by the Minerals Management Service of the United States Department of the Interior for underpayment of royalties and the State of Montana Department of Revenue for underpayment of production taxes related to coal previously sold to Black Butte. The supplier is contesting these claims; however, should the claims be successful, the supplier will claim reimbursement from Black Butte. In 1998, the Courts ruled in favor of the State of Montana. The supplier is appealing to the Montana State Supreme Court, however, the Company recorded $15.2 million as its proportionate share of the Montana Department of Revenue assessment related to coal production taxes. The Company's proportionate share of the liability for underpaid royalties and interest to the Minerals Management Service of the United States Department of the Interior, if any, could range from zero to $6.7 million.
15. SHAREHOLDERS' EQUITY
Stock Option and Retention Stock Plans. Pursuant to the Company's stock option and retention stock plans, 11,062,582 and 5,999,439 shares of Common Stock were available for grant to employees and directors at the end of December 31, 1999 and 1998, respectively. In May 1999, the Company's shareholders approved a 7.5 million increase in the number of shares available for grants and awards to employees and directors. Shares may either be granted as options to purchase Common Stock or as awards of retention stock. Options to purchase Common Stock under the plans are generally granted with an exercise price equal to the fair market value at the date of grant and are exercisable for a period of up to 10 years from grant date. Option grants have been made to directors, officers and employees and vest over periods up to 10 years from the grant date. Retention stock is awarded under the plans to eligible employees, subject to forfeiture if employment
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terminates during the prescribed retention period, generally one to five years from grant, subject to accelerated vesting in some situations.
In the first quarter of 1999, options covering 1,171,439 shares of Company common stock were granted to directors, officers and certain non-officer executives of the Company, each with an exercise price of $9.44 per share, a one-year vesting period and a ten-year term. In addition, 1,474,439 shares of retention stock were awarded to officers and certain non-officer executives with a vesting schedule of one-third per year over a three-year period commencing on the first anniversary of the award date, subject to accelerated vesting upon the achievement of certain Company common stock price objectives. These stock price objectives were achieved in April and May 1999, resulting in the acceleration of vesting of all such shares of retention stock. Of the Company's $17.0 million compensation expense in 1999 that was recorded for retention stock, $14.8 million was recorded in connection with the vesting of the January 1999 retention stock awards.
The status of the Company's stock-based compensation programs is as follows:
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Weighted-average fair value on the dates of option grants and retention share awards:
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(a) Calculated in accordance with the Black-Scholes option pricing model, using the following weighted average assumptions:
(b) Represents market value on grant date.
Options to purchase Common Stock were as follows:
Since the Company applies the intrinsic value method in accounting for its stock option and retention stock plans, it generally records no compensation cost for its stock option plans. This method calculates compensation expense on the measurement date (usually the date of grant or award) as the excess of the current market price of the underlying common stock of the Company 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. Compensation cost recognized relating to retention stock was $17.0 million, $6.5 million and $11.6 million in 1999, 1998 and 1997, respectively. Approximately $14.8 million of the $17.0 million 1999 compensation costs was related to the vesting of the January 1999 retention stock awards. If compensation cost for the Company's stock option plan had been determined based on the fair value at the grant dates for awards under the plan, the Company's net income would have been reduced by $26.7 million in 1999, $13.8 million in 1998 and $8.0 million in 1997. Basic and diluted earnings per share would have been reduced by $0.11 per share in 1999, $0.06 per share in 1998 and $0.03 per share in 1997.
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Earnings Per Share. Basic earnings per share ("EPS") excludes dilution and is computed by dividing income available to common shareholders by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The reconciliation between basic earnings per share and diluted earnings per share is as follows:
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(a) Options outstanding, as discussed above, have been excluded from the 1998 calculation of diluted earnings per share due to anti-dilution.
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Employee Stock Ownership Plan. Effective January 2, 1997, the Company instituted an employee stock ownership plan ("ESOP") for eligible U.S. employees. The ESOP purchased 3.7 million shares or $107.3 million of newly issued common stock (the "ESOP Shares") from the Company, to be used to fund the Company's matching obligation under its 401(k) Thrift Plan. All domestic 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 were pledged as collateral for the loan. As loan payments are made, shares are released from collateral, based on the proportion of debt service paid. Scheduled principal and interest requirements are $5.9 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 are included in the computation of earnings per share as such ESOP Shares are released from collateral. 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.
As of December 31, 1999, allocated and unallocated shares in the ESOP were 958,472 and 2,741,528, respectively. As of December 31, 1998, allocated and unallocated shares were 483,216 and 3,216,784, respectively. The fair value of unallocated ESOP shares at December 31, 1999 and 1998 was $35.0 million and $29.2 million, respectively. During 1999, 1998 and 1997, compensation cost related to the allocation of ESOP shares to participants' accounts was $4.4 million, $6.3 million and $5.3 million, respectively.
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 ("Rights Agreement"). Under the 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 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.
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
During 1999, the Company repurchased 869,681 shares at a cost of $12.6 million primarily in connection with the Company's retention stock program. Also during 1999, the Company reissued 259,605 shares of repurchased stock for $3.3 million to settle deferred compensation liabilities for several former executives. During 1998, the Company repurchased 837,500 shares at a cost of $18.6 million and 449,788 shares at a cost of $8.1 million, in connection with the Company's retention stock and options, respectively.
Other Comprehensive Income. The Company's other comprehensive income is as follows:
16. OTHER INCOME -- NET
Other income (expense) -- net consists of the following:
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(a) Related to cost incurred with the unsuccessful takeover attempt of Pennzoil Company.
UNION PACIFIC RESOURCES GROUP INC.
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) Reserves at the end of 1997 include 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.
B. DRILLING ACTIVITY
Drilling activity is summarized as follows:
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(a) In addition, at December 31, 1999, 26 gross wells (17 net wells) were in the process of being drilled.
C. AVERAGE SALES PRICE AND COST
The average producing properties sales prices, after hedging results and costs are set forth below:
D. AVERAGE DAILY PRODUCTION AND SALES VOLUME
The average producing properties daily production and sales volume are set forth below:
E. ACREAGE AND WELLS
Oil and gas leasehold acreage is as follows(a):
Productive oil and gas wells are as follows:
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(a) In addition, the Company has fee mineral ownership of approximately 9.4 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 2,265 are multiple completions, 2,011 of which are gas wells.
F. CAPITALIZED EXPLORATION AND PRODUCTION COSTS
Capitalized exploration and production costs are as follows(a):
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 $17.9 million in 1999, $24.2 million in 1998 and $23.5 million in 1997 and delay rentals of $8.3 million in 1999, $12.3 million in 1998 and $14.8 million in 1997.
(b) Excludes capital expenditures relating to discontinued operations of $33.7 million in 1999, $143.8 million in 1998 and $343.3 million in 1997.
H. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES(A)
The results of operations for producing activities is set forth below:
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(a) General and administrative expenses, other income/expense and interest costs have been excluded in computing these results of operations. Revenues include net gains from sales of assets of $148.0 million in 1999, $139.6 million in 1998 and $18.3 million in 1997. Depreciation, depletion and amortization includes asset impairments of $65.1 million in 1999, $1.2 billion in 1998 and $20.2 million in 1997.
I. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATES TO PROVED OIL AND GAS RESERVES
The standardized measure of discounted cash flows relating to oil and gas reserves are set forth below:
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 on the New York Mercantile Exchange adjusted for appropriate regional price differentials. Such weighted average prices for 1999, 1998 and 1997 were $2.50 per Mcfe, $1.63 per Mcfe and $2.24 per Mcfe, respectively. 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 crude oil, natural gas and NGLs, 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.
J. SELECTED QUARTERLY DATA
Selected unaudited quarterly data are as follows:
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(a) First quarter 1999 net income reflects the sale of the Company's GPM business segment for $157.0 million after-tax gain and an after-tax loss of $23.8 million on discontinued operations.
(b) Second quarter 1998 results reflect the impact of purchase of the Norcen Acquisition. Fourth quarter 1998 results reflect the decrease in hydrocarbon prices and a $1.2 billion impairment of certain oil and gas assets.
(c) Certain amounts have been restated from amounts previously reported in the Company's SEC Form 10-Q for the periods ended March 31, 1999, June 30, 1999 and September 30, 1999.
(d) Certain amounts have been restated for discontinued operations from amounts previously reported in the Company's SEC Form 10-Q for the periods ended March 31, 1998, June 30, 1998 and September 30, 1998 (See Note 3).
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 Beneficial Ownership -- Section 16(a) Reporting Compliance 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 Outside Directors 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 17, 2000, by each director and nominee for director, the five most highly compensated current executive officers, a former chief executive officer, a former executive officer, and directors and current executive officers as a group is set forth in the Security Ownership of Certain Executive Officers, Directors and Certain Beneficial Owners segment of the Proxy Statement and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
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 in Item 8 of this Form 10-K.
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. Management contracts or compensatory plans, contracts or arrangements with directors and executive officers of the Company are listed in Exhibits 10.3 through 10.14(b).
(b) Reports on Form 8-K.
On January 28, 2000, the Company filed a Current Report on Form 8-K announcing the Company's 1999 annual operating results, net income and certain other financial and statistical information.
On February 17, 2000, the Company filed a Current Report on Form 8-K updating its January 25, 2000 press release and the January 28, 2000 Current Report on Form 8-K to include information with respect to reserves at year-end 1999 and finding and development costs for 1999.
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 27th day of March, 2000.
UNION PACIFIC RESOURCES GROUP INC.
By: /s/ MORRIS B. SMITH --------------------------------------- Morris B. Smith, Vice President, Chief Financial Officer and Treasurer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below, on this 27th day of March, 2000, by the following persons on behalf of the registrant and in the capacities indicated.
INDEX TO EXHIBITS