10-12G/A 1 0001.txt ---------------------------------------------------------------------- ---------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 ------------------------ FORM 10/A (AMENDMENT NO. 2 TO FORM 10) GENERAL FORM FOR REGISTRATION OF SECURITIES PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934 QUESTAR MARKET RESOURCES, INC. (Exact name of registrant as specified in its charter) UTAH (State or other jurisdiction of incorporation or organization) 180 East 100 South P.O. Box 45601 Salt Lake City, Utah 84145-0601 (Zip Code) (Address of principal executive offices) 87-0287750 (I.R.S. Employer Identification No.) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (801) 324-5202 SECURITIES TO BE REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: TITLE OF EACH CLASS TO BE SO REGISTERED NONE NAME OF EACH EXCHANGE ON WHICH EACH CLASS IS TO BE REGISTERED NONE SECURITIES TO BE REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: COMMON STOCK, $1.00 PAR VALUE (Title of class) REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I1(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT. TABLE OF CONTENTS Page Item 1. Business.................................................4 Item 2. Financial Information...................................12 Item 3. Properties..............................................19 Item 4. Security Ownership of Certain Beneficial Owners and Management.......................................27 Item 5. Directors and Executive Officers........................27 Item 6. Executive Compensation..................................29 Item 7. Certain Relationships and Related Transactions..........29 Item 8. Legal Proceedings.......................................29 Item 9. Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters........30 Item 10. Recent Sales of Unregistered Securities.................30 Item 11. Description of Registrant's Securities to be Registered.30 Item 12. Indemnification of Officers and Directors...............31 Item 13. Financial Statements and Supplementary Data.............32 Item 14. Changes in and Disagreements with Accountants and Financial Disclosure.................................63 Item 15. Financial Statements and Exhibits.......................63 GLOSSARY OF COMMONLY USED OIL AND GAS TERMS "Bbl" means barrel. One barrel is the equivalent of 42 standard U.S. gallons. "Bcf" means billion cubic feet, a common unit of measurement of natural gas. "Bcfe" means billion cubic feet of natural gas equivalents. Oil volumes are converted to natural gas equivalents using the ratio of one barrel of crude oil to six thousand cubic feet of natural gas. "Btu" means British thermal unit, measured as the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit. "Completion" means the completion of the processes necessary before production of oil or natural gas occurs (e.g., perforating the casing; installing permanent equipment in the well; installing required surface production equipment), or in the case of a dry hole, the reporting of abandonment to the appropriate agency. "Development well" means a well drilled into a known producing formation in a previously discovered field. "Dry hole" means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. "Dth" means decatherms or ten therms. One decatherm equals one million Btu. "Exploratory well" means a well drilled into a previously untested geologic structure to determine the presence of oil or gas. "Gross" natural gas and oil wells or "gross" acres equals the number of wells or acres in which we have an interest. "MBbls" means thousand barrels. "Mcf" means thousand cubic feet. "Mcfe" means thousand cubic feet of natural gas equivalents. "MDths" means thousand decatherms. -2- "MMBbls" means million barrels. "MMBtu" means million British thermal units. "MMcf" means million cubic feet. "MMDth" means million decatherms. "Net" gas and oil wells or "net" acres are determined by multiplying gross wells or acres by our working interest in those wells or acres. "NGL" means natural gas liquids. "Proved reserves" means those quantities of natural gas and crude oil, condensate, and natural gas liquids on a net revenue interest basis, which geological and engineering data demonstrate with reasonable certainty to be recoverable under existing economic and operating conditions. "Proved developed reserves" include proved developed producing reserves and proved developed behind-pipe reserves. "Proved developed producing reserves" include only those reserves expected to be recovered from existing completion intervals in existing wells. "Proved undeveloped reserves" include those reserves expected to be recovered from new wells on proved undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. "Reservoir" means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs. "Working interest" means an interest that gives the owner the right to drill, produce, and conduct operating activities on a property and receive a share of any production. DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This Form includes "forward-looking statements" within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this Form, including, without limitation, statements regarding the Company's future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as "may", "will", "could", "expect", "intend", "project", "estimate", "anticipate", "believe", "forecast", or "continue" or the negative thereof or variations thereon or similar terminology. Although these statements are made in good faith and are reasonable representations of the Company's expected performance at the time, actual results may vary from management's stated expectations and projections due to a variety of factors. Important assumptions and other significant factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements include changes in general economic conditions, gas and oil prices and supplies, competition, regulation of the Wexpro settlement agreement, availability of gas and oil properties for sale or for exploration and other factors beyond the control of the Company. These other factors include the rate of inflation, the weather and other natural phenomena, the effect of accounting policies issued periodically by accounting standard-setting bodies, and adverse changes in the business or financial condition of the Company. -3- ITEM 1. BUSINESS General Questar Market Resources Inc. (the "Company" or "QMR", which reference shall include the Company's wholly-owned subsidiaries) is a wholly-owned subsidiary of Questar Corporation. Questar Corporation ("Questar") is a publicly traded (NYSE: STR) diversified natural gas company with two principal business units - Market Resources and Regulated Services. QMR and its subsidiaries comprise the Market Resources unit of Questar and as such engage in oil and gas exploration, development and production; gas gathering and processing; wholesale gas, electricity, and hydrocarbon liquids trading; and the acquisition of producing oil and gas properties. As noted in the following Questar organization chart, QMR is a subholding company of Questar that conducts its activities through Questar Exploration and Production Company ("Questar E&P") and its Canadian subsidiaries Celsius Energy Resources Ltd. ("Celsius Ltd.") and Canor Energy Ltd. ("Canor"); Wexpro Company ("Wexpro"); Questar Gas Management Company ("Questar Gas Management"); and Questar Energy Trading Company ("Questar Energy Trading"). Questar Corporation Questar InfoComm, Inc. (Information Services) Questar Market Resources, Inc. (Subholding Company) Wexpro Company (Manages and develops cost of service properties for Questar Gas) Questar Exploration and Production Company (Exploration and Production) Celsius Energy Resources Ltd. and Canor Energy Ltd. (Exploration & Production - Canada) Questar Energy Trading Company (Wholesale Energy Marketing) Questar Gas Management Company (Gathering and Processing) Questar Regulated Services Company (Subholding Company) Questar Gas Company (Retail Distribution) Questar Pipeline Company (Transportation and Storage) Management of Questar has identified QMR as the primary growth area within Questar's business strategy. Questar expects to spend 70% of its capital budget funds over the next five years on non-regulated activities, primarily within QMR, to expand reserves through drilling and acquisitions and to enlarge its infrastructure of gathering systems, processing plants, header facilities, and nonregulated storage facilities. Management of QMR believes that the diversity of the activities pursued by QMR enhances its basic strategy to pursue complementary growth. As the exploration and production companies find or acquire new reserves, Questar Gas Management should have more opportunities to expand gathering and processing activities, and Questar Energy Trading should have more physical production to support its marketing programs. -4- Business Strategy QMR believes it can best meet and balance the expectations of its parent and fixed income investors by pursuing the following strategies in its business: * achieve a prudent, disciplined program to grow reserves * provide stakeholder value performance in both the short and long term * employ hedging and other risk management tools to manage cyclicality * maintain a strong balance sheet that permits prudent growth opportunities * maintain a portfolio of quality drilling prospects * identify and divest non-core and marginal assets and activities * proactively avoid litigation risks * employ technology and proven innovations to reduce costs Oil and Gas Exploration and Production - Questar E&P, Celsius Ltd., and Canor Together, QMR's exploration and production ("E&P") subsidiaries form a unique E&P group that conducts a blended program of low-cost development drilling, low-risk reserve acquisition, and high-quality exploration. A low-risk oil and gas reserve acquisition is considered by QMR to be one where (i) existing proved developed producing reserves make up a substantial percentage (75%+) of the overall value of the transaction with the remaining value supported by proved undeveloped reserves recognized by the seller or developed by QMR; (ii) cash flow from the properties, and/or borrowing capacity associated with the properties, is sufficient to support development of the acquisition properties; and (iii) the geographic location of the properties and the technology required to develop the underlying reserves are within our known areas of expertise. The E&P group also maintains a geographical balance and diversity, while concentrating its activities in core areas in which it has accumulated geologic knowledge and developed significant management expertise. Core areas of activity include the Rocky Mountain Region of Wyoming and Colorado; the Mid-Continent Region of Oklahoma, the Texas Panhandle, East Texas, and the Upper Gulf Coast; the Southwest Region of northwest New Mexico and southwest Colorado; and the Western Canada Sedimentary Basin located primarily in the Canadian province of Alberta. At December 31, 1999, the Company had proved reserves of 597.6 Bcfe of natural gas, crude oil and natural gas liquids associated with its oil and gas exploration and development activities. On an energy equivalent basis ratio of six Mcf of natural gas to one Bbl of crude oil or natural gas liquids, natural gas comprised 86% of total proved reserves. Proved developed reserves comprised 84% of the total proved reserves on an energy equivalent basis. A detailed description of the Company's proved reserves and their geographic diversity can be found under "Item 3. Properties." These proved reserve volumes do not include the cost of service reserves managed and developed by Wexpro for Questar Gas Company, an affiliate of the Company ("Questar Gas"). See "Development and Production - Wexpro" below. Development and Production - Wexpro QMR conducts development drilling and provides production services to Questar Gas through Wexpro. Wexpro was incorporated in 1976 as a subsidiary of Questar Gas. Questar Gas' efforts to transfer producing properties and leasehold acreage to Wexpro resulted in protracted regulatory proceedings and legal adjudications that ended with a court-approved settlement agreement that was effective August 1, 1981. A summary of the Wexpro settlement agreement is contained in Note 10 of the Notes to Consolidated Financial Statements under Item 13 of this Form 10. Ownership of Wexpro was moved from Questar Gas to QMR in 1982. Wexpro manages and develops cost of service properties for which the operations and return on investment are regulated by the Wexpro settlement agreement. Cost of service reserves are derived from properties that primarily produce oil ("productive oil reservoirs") as well as properties that primarily produce gas ("productive gas reservoirs"). Pursuant -5- to the terms of the settlement agreement, all hydrocarbon reserves (oil, natural gas liquids and natural gas) in productive oil reservoirs are owned by Wexpro. All hydrocarbon reserves associated with productive gas reservoirs are owned by Questar Gas. Wexpro manages and develops all cost of service reserves, in accordance with the provisions of the settlement agreement, regardless of reserve ownership. Wexpro, unlike QMR's other E&P companies, generally does not conduct exploratory operations and does not acquire leasehold acreage for exploration activities. It conducts oil and gas development and production activities on certain producing properties located in the Rocky Mountain region under the terms of the settlement agreement. Wexpro produces gas from specified properties for Questar Gas and is reimbursed for its costs plus a return on its investment. In connection with its operations under the settlement agreement, Wexpro charges Questar Gas for its cost plus a specified rate of return (18.9% after tax at the end of 1999 and adjusted annually based on a specified formula) on its net investment in such properties adjusted for working capital and deferred taxes. Under the terms of the settlement agreement, Wexpro bears all dry hole costs. The settlement agreement is monitored by the Utah Division of Public Utilities, the staff of the Public Service Commission of Wyoming ("PSCW"), and experts retained by those agencies. The gas volumes produced by Wexpro for Questar Gas are reflected in the latter's rates at cost of service. Cost of service gas produced by Wexpro satisfied approximately 49% of Questar Gas' system requirements during 1999. Questar Gas relies upon Wexpro's drilling program to develop the properties from which the cost of service gas is produced. During 1999, the average wellhead cost of cost of service gas was $1.50 per Dth, which is lower than Questar Gas' average price for field-purchased gas. To fulfill its obligations to Questar Gas under the settlement agreement, Wexpro must continue to be a prudent operator. Wexpro participates in drilling activities in response to the demands of other working interest owners, to protect its rights, and to meet the needs of Questar Gas. Wexpro, in 1999, produced 38.9 Bcf of natural gas from cost of service properties and added cost of service reserves of 52.4 Bcf through drilling activities and reserve estimate revisions. Wexpro has an ownership interest in the wells and appurtenant facilities related to its oil properties and in the wells and facilities that have been installed to develop and produce gas properties described above since August 1, 1981. Gathering, Processing and Marketing - Questar Gas Management and Questar Energy Trading Questar Gas Management conducts gathering and processing activities in the Rocky Mountain and Mid-Continent areas. Its activities are not subject to regulation by the Federal Energy Regulatory Commission ("FERC"), because it is not engaged in transporting gas or selling gas for resale in interstate commerce. The Natural Gas Act of 1938 specifically provides that the FERC's jurisdiction does not extend to facilities involved in the production or gathering of natural gas. Questar Gas Management was formed in 1993, as a wholly-owned subsidiary of Questar Pipeline Company, an affiliate of the Company ("Questar Pipeline"), to construct and operate the Blacks Fork Processing Plant in southwestern Wyoming. It expanded in 1996 when Questar Pipeline transferred its gathering assets and activities to Questar Gas Management. In mid-1996, ownership of Questar Gas Management was moved from Questar Pipeline to QMR and Questar Gas Management acquired the processing plants that formerly belonged to Questar E&P. Questar Gas Management's gathering system, which consists of 1,400 miles of gathering lines, compressor stations, field dehydration plants, and measuring stations, was largely built to gather production from Questar Gas' cost of service properties. Under the terms of a contract that was assigned with the gathering assets from Questar Pipeline, Questar Gas Management is obligated to gather Questar Gas' cost of service production for the life of the properties. During 1999, Questar Gas Management gathered 32.1 MMDth of natural gas for Questar Gas, compared to 29.9 MMDth in 1998, for which it received $4.7 million and $5.0 million in demand charges in 1999 and 1998, respectively, from Questar Gas. Questar Gas Management's total gas gathering volumes were 136.7 MMDth in 1999 compared to 120.5 MMDth in 1998. Questar Gas Management's gathering system was originally built as part of a regulated company. Questar Gas Management now must operate in a different competitive environment. Often, new wells will have connections with more than one gathering system, and producers insist that gathering systems be tied to more than one pipeline. -6- In addition to gathering activities, Questar Gas Management is also engaged in processing activities. It owns a 50% interest in the Blacks Fork Processing Plant, which has a daily capacity of 84 MMcf and may be expanded during 2000. This plant, which is located in southwestern Wyoming, strips liquids (e.g., ethane, butane) from natural gas volumes. Questar Gas Management and Wexpro jointly own a new processing facility located in the Canyon Creek area of southwestern Wyoming that has an operating capacity of 45 MMcf per day. Questar Gas Management also owns interests in other processing plants in the Rocky Mountain and Mid-Continent areas. Questar Energy Trading conducts energy marketing activities. It combines gas volumes purchased from third parties and equity production (production that is produced by other QMR subsidiaries) to build a flexible and reliable portfolio. Questar Energy Trading aggregates supplies of natural gas for delivery to large customers, including industrial users, and other marketing entities. During 1999, Questar Energy Trading marketed a total of 101.1 MMDth of natural gas, 2.0 MMBbls of liquids, and 10,000 megawatt-hours of electricity and earned a gross profit margin of $4.1 million. Questar Energy Trading uses derivatives as a risk management tool to provide price protection for physical transactions involving equity production and marketing transactions. Questar Energy Trading executes hedges for equity production on behalf of Questar E&P and does so with a variety of contracts for different periods of time. See "Item 2. Financial Information - Market Risk." As a wholesale marketing entity, Questar Energy Trading concentrates on markets in the Pacific Northwest, Rocky Mountains, Midwest, Southwest, California, and western Canada that are close to reserves owned by affiliates or accessible by major pipelines. To sustain its activities in an increasingly competitive environment in which sellers and purchasers are becoming more sophisticated, Questar Energy Trading needs to expand its capabilities. Through a new limited liability company, it has filed an application with the FERC and obtained authorization to construct and operate a private storage reservoir in southwestern Wyoming adjacent to several interstate pipelines and is negotiating partnerships with electricity providers and others to obtain additional capability, expertise, and access to sophisticated information technology. Relationship with Questar QMR and Questar are parties to several agreements which govern different aspects of the QMR - Questar relationship. The more significant of these agreements are described below. Also see Note 9 of the Notes to Consolidated Financial Statements under Item 13 of this Form 10. Tax Sharing Arrangement with Questar -- QMR accounts for income tax expense on a separate return basis. Pursuant to the Internal Revenue Code and associated regulations, the Company's operations are consolidated with those of Questar and its subsidiaries for income tax reporting purposes. The Company records tax benefits as they are generated. The Company receives payments from Questar for such tax benefits as they are utilized on the consolidated return. Wexpro Settlement Agreement with Questar Gas -- Wexpro and Questar Gas are parties to the Wexpro Settlement Agreement. Wexpro's operations are subject to the terms of this agreement. The agreement became effective August 1, 1981, and sets forth the rights of Questar Gas' utility operations to share in the results of Wexpro's operations. The agreement was approved by the Public Service Commission of Utah ("PSCU") and PSCW in 1981 and affirmed by the Supreme Court of Utah in 1983. Major provisions of the settlement agreement are as follows: a. Wexpro continues to hold and operate all oil-producing properties (productive oil reservoirs) previously transferred from Questar Gas' nonutility accounts. The oil production from these properties is sold at market prices, with the revenues used to recover operating expenses and to give Wexpro a return on its investment. The after tax rate of return is adjusted annually and is approximately 13.7%. Any net income remaining after recovery of expenses and Wexpro's return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%. -7- b. Wexpro conducts developmental oil drilling on productive oil reservoirs and bears any costs of dry holes. Oil discovered from these properties is sold at market prices, with the revenues used to recover operating expenses and to give Wexpro a return on its investment in successful wells. The after tax rate of return is adjusted annually and is approximately 18.7%. Any net income remaining after recovery of expenses and Wexpro's return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%. c. Amounts received by Questar Gas from the sharing of Wexpro's oil income are used to reduce natural gas costs to utility customers. d. Wexpro conducts developmental gas drilling on productive gas properties (productive gas reservoirs) and bears any costs of dry holes. Natural gas produced from successful drilling is owned by Questar Gas. Wexpro is reimbursed for the costs of producing the gas plus a return on its investment in successful wells. The after tax return allowed Wexpro is approximately 21.7%. e. Wexpro operates natural gas properties owned by Questar Gas. Wexpro is reimbursed for its costs of operating these properties, including a rate of return on any investment it makes. This after tax rate of return is approximately 13.7%. Transportation Agreements with Affiliates -- As an affiliate of QMR, Questar Pipeline transports natural gas produced from properties operated by Wexpro. Questar Pipeline also transports volumes of natural gas marketed by Questar Energy Trading, another QMR subsidiary. Transfer of Gas Gathering Assets -- In 1996, Questar Pipeline transferred approximately $55 million of gas-gathering assets to its subsidiary Questar Gas Management. Questar Gas Management was subsequently transferred to QMR on July 1, 1996. The transaction was in the form of a stock dividend payable to Questar, which stock Questar then contributed to QMR. Government Regulation QMR's operations are subject to various levels of government controls and regulation in the United States and Canada. United States Regulation. In the United States, legislation affecting the oil and gas industry has been pervasive and is subject to continuing review for amendment or expansion. Pursuant to such legislation, numerous federal, state and local departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for the failure to comply. Such laws and regulations have a significant impact on oil and gas drilling and production activities, increase the cost of doing business and, consequently, affect profitability. Inasmuch as new legislation affecting the oil and gas industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, QMR is unable to predict the future cost or impact of complying with such laws and regulations. Exploration and Production. QMR's United States operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells; maintaining bonding requirements in order to drill or operate wells; submitting and implementing spill prevention plans; submitting notification relating to the presence, use and release of certain contaminants incidental to oil and gas operations; and regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities, surface usage and the restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transporting of production. QMR's operations are also subject to various conservation matters, including the regulation of the size of drilling and spacing units or -8- proration units, the number of wells which may be drilled in a unit, and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas, and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas QMR can produce from its wells and to limit the number of wells or the locations at which QMR can drill. Certain of QMR's oil and gas leases, including most of its leases in the San Juan Basin and many of the Company's leases in southeast New Mexico and Wyoming, are granted by the federal government and administered by various federal agencies. Such leases require compliance with detailed federal regulations and orders which regulate, among other matters, drilling and operations on lands covered by these leases, and calculation and disbursement of royalty payments to the federal government. Environmental and Occupational Regulations. Various federal, state and local laws and regulations concerning the discharge of contaminants into the environment, the generation, storage, transportation and disposal of contaminants or otherwise relating to the protection of public health, natural resources, wildlife and the environment may affect the Company's operations and costs. In particular, the Company's oil and gas exploration, development and production operations, its activities in connection with storage and transportation of liquid hydrocarbons, and its use of facilities for treating, processing, recovering or otherwise handling hydrocarbons and wastes therefrom are subject to environmental regulation by governmental authorities. Such regulation has increased the cost of planning, designing, drilling, installing, operating and abandoning the Company's oil and gas wells and other facilities. Additionally, these laws and regulations may impose substantial liabilities for the Company's failure to comply with them or for any contamination resulting from the Company's operations. QMR takes the issue of environmental stewardship very seriously and works diligently to comply with applicable environmental rules and regulations. Compliance with such laws and regulations has not had a material effect on the Company's operations or financial condition in the past. However, because environmental laws and regulations are becoming increasingly more stringent, there can be no assurances that such laws and regulations or any environmental law or regulation enacted in the future will not have a material effect on the Company's operations or financial condition. QMR is not aware of any currently pending environmental legislation or regulation in the United States that would have a material adverse effect on the Company if enacted. QMR is also subject to laws and regulations concerning occupational safety and health. Due to the continued changes in these laws and regulations, and their judicial construction, QMR is unable to predict with any reasonable degree of certainty its future costs of complying with these laws and regulations. Canadian Regulation. The oil and gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulation will materially affect QMR's Canadian operations, nor is it expected that the application of these controls and regulations would be any more burdensome to QMR than to other companies involved in oil and gas exploration and production activities in Canada. The following are the most important areas of control and regulation. The North American Free Trade Agreement. The North American Free Trade Agreement ("NAFTA") which became effective on January 1, 1994, carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the U.S. or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy -9- exported relative to the supply of the energy resource; (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All parties to NAFTA are also prohibited from imposing minimum export or import price requirements. Royalties and Incentives. Each province and the federal government of Canada have legislation and regulations governing land tenure, royalties, production rates and taxes, environmental protection and other matters under their respective jurisdictions. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time, the governments of Canada, Alberta and British Columbia have also established incentive programs such as royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing the cash flow to the producer. Pricing and Marketing. The price received by the Company for its oil and natural gas is generally determined by market factors, most of which are beyond the Company's control. An order from the National Energy Board ("NEB") is required for oil exports from Canada. Any oil export to be made pursuant to an export contract of longer than one year, in the case of light crude, and two years, in the case of heavy crude, duration (up to 25 years) requires an exporter to obtain an export license from the NEB. The issue of such a license requires the approval of the Governor in Council. Natural gas exported from Canada is also subject to similar regulation by the NEB. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts in excess of two years must continue to meet certain criteria prescribed by the NEB. The governments of Alberta and British Columbia also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations. Environmental Regulation. The oil and natural gas industry is subject to environmental regulation pursuant to local, 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. QMR is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment. QMR's unreimbursed expenditures in 1999 concerning such matters were immaterial, but QMR cannot predict with any reasonable degree of certainty its future exposure concerning such matters. QMR is not aware of any currently pending environmental legislation or regulation in Canada that would have a material adverse effect on the Company if enacted. Investment Canada Act. The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In certain circumstances, the acquisition of natural resource properties may be considered to be a transaction requiring such approval. Insurance Coverage Maintained with Respect to Operations Principally through shared arrangements with Questar, the Company maintains insurance policies covering its operations in amounts and areas of coverage normal for a company of its size in the oil and gas exploration and production industry. These include, but are not limited to, worker's compensation, employers' liability, automotive -10- liability, certain environmental claims and general liability. In addition, umbrella liability and operator's extra expense policies are maintained. All such insurance is subject to normal deductible levels. Competition The oil and gas business is highly competitive. The Company faces competition in all aspects of its business, including, but not limited to acquiring reserves, leases, licenses and concessions; obtaining goods, services and labor needed to conduct its operations and manage the Company; and marketing its oil and gas. Intense competition occurs with respect to marketing, particularly of natural gas. The Company's competitors include multinational energy companies, other independent producers and individual producers and operators. Many competitors have greater financial and other resources than the Company. Seasonal Nature of Business Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. Natural Gas and Oil Marketing The Company markets substantially all of its own natural gas and oil production. The revenues generated by the Company's operations are highly dependent upon the prices of, and demand for, oil and gas. The price received by the Company for its crude oil and natural gas depends upon numerous market factors, the majority of which are beyond the Company's control, including economic conditions in the United States and elsewhere, the world political situation, OPEC actions, and governmental regulation. The fluctuation in world oil prices continues to reflect market uncertainty regarding the balance of world demand for and supply of oil and gas. The fluctuation of natural gas prices reflects the seasonal swings of storage inventory, weather conditions, and increasing utilization of natural gas for electric generation as it affects overall demand. Decreases in the prices of oil and gas have had, and could have in the future, an adverse effect on the Company's development and exploration programs, proved reserves, revenues, profitability and cash flow. See "Item 2. Financial Information - Qualitative and Quantitive Disclosure about Market Risk." Customers QMR sells its gas production to a variety of customers including pipelines, gas marketing firms, industrial users and local distribution companies. Existing gathering systems and interstate and intrastate pipelines are used to consummate gas sales and deliveries. The principal customers for QMR's crude oil production are refiners, remarketers and other companies, some of which have pipeline facilities near the producing properties. In the event pipeline facilities are not conveniently available, crude oil is trucked to storage, refining or pipeline facilities. Employees and Offices As of December 1, 2000, the Company had 425 full-time employees. None of the Company's employees are represented by organized labor unions. The Company also engages independent consulting petroleum engineers, environmental professionals, geologists, geophysicists, landmen and attorneys on a fee basis. -11- The Company's executive offices are located at 180 East 100 South, P. O. Box 45601, Salt Lake City, Utah 84145-0601, and its telephone number is (801) 324-2600. Regional operating offices are also maintained in Denver, Colorado; Oklahoma City, Oklahoma; Tulsa, Oklahoma; Rock Springs, Wyoming; and Calgary, Alberta. ITEM 2. FINANCIAL INFORMATION Selected Financial Data The following tables sets forth certain selected financial data of the Company. This information should be read in conjunction with the "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in this item, and the Consolidated Financial Statements and the notes thereto included in "Item 13. Financial Statements and Supplementary Data." The annual financial statements of QMR included in Item 13 of this Form 10 have been audited by Ernst & Young LLP, independent auditors, as experts in accounting and auditing. Information disclosed in the following table for the three months ended March 31, 2000 and 1999, and for the years ended December 31, 1996 and 1995 has not been audited.
For the Three Months Ended March 31, For the Year Ended December 31, 2000 1999 1999 1998 1997 1996 1995 (In Thousands) Revenues $141,761 $115,846 $498,311 $458,272 $523,640 $484,080 $309,466 Write-down of full cost oil and gas properties 31,000 6,000 Write-down of gas gathering properties 3,000 Operating income 25,675 14,343 76,778 25,629 54,837 64,688 43,853 Debt Expense 5,370 4,263 17,363 12,631 10,882 8,699 6,323 Income from continuing operations 15,049 8,253 45,866 16,725 39,111 42,447 31,654 Loss from discontinued operations (563) (1,021) (322) Net Income 15,049 8,253 45,866 16,162 38,090 42,125 31,654 Net Cash provided from operating activities 31,132 36,971 140,857 127,513 136,935 83,309 79,596 Net cash used in investing activities 80,027 12,789 94,426 246,689 81,292 184,453 17,606 Net cash provided from (used in) financing activities 51,448 (21,510) (48,281) 120,060 (54,615) 97,508 (63,200) Cash dividends paid to Questar 4,325 4,150 16,600 15,900 16,325 14,500 13,000 At March 31, At December 31, 2000 1999 1999 1998 1997 1996 1995 (In Thousands) Total assets $918,334 $804,227 $847,891 $815,153 $696,675 $696,754 $457,620 Short-term debt 49,700 111,400 24,500 121,800 44,300 78,000 14,000 Long-term debt 293,074 186,008 264,894 181,624 133,387 120,000 53,000 Common equity 399,555 365,715 387,834 359,638 359,283 337,666 282,144
-12- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis addresses changes in the Company's financial condition and results of operations. Results of Operations -
Three Months Ended March 31, Year Ended December 31, 2000 1999 1999 1998 1997 (In Thousands) Operating Income - Revenues Natural gas sales $36,772 $28,011 $125,245 $98,767 $89,489 Oil and natural gas liquids sales 15,198 7,959 41,521 36,722 53,722 Cost of service gas operations 17,730 15,658 61,705 61,448 52,950 Energy marketing 63,760 58,004 243,296 234,565 297,413 Gas gathering and 7,099 4,924 22,341 21,954 25,998 processing Other 1,202 1,290 4,203 4,816 4,068 Total revenues 141,761 115,846 498,311 458,272 523,640 Operating expenses Energy purchases 63,893 56,392 239,201 230,462 291,851 Operating and maintenance 22,918 20,169 79,916 73,763 72,958 Depreciation and amortization 20,977 19,605 78,608 71,377 67,078 Write-down of full cost oil and gas properties 31,000 6,000 Write-down of gas gathering properties 3,000 Other taxes 7,314 5,128 21,516 24,988 25,569 Wexpro settlement agreement - Oil income sharing 984 209 2,292 1,053 2,347 Total operating expenses 116,086 101,503 421,533 432,643 468,803 Operating income $ 25,675 $ 14,343 $ 76,778 $ 25,629 $ 54,837 Operating Statistics - Production volumes (excluding cost of service activities) Natural gas (MMcf) 16,950 15,048 62,712 51,309 47,442 Oil and NGL (MBbl) 554 606 2,311 2,340 2,377 Production revenue (excluding cost of service activities) Natural gas (per Mcf) $ 2.17 $ 1.86 $ 2.00 $ 1.92 $ 1.89 Oil and NGL (per Bbl) $ 21.64 $ 10.65 $ 13.92 $ 12.70 $ 17.77 Wexpro investment base, net of deferred income taxes (in thousands) $109,690 $ 98,343 $108,890 $ 97,594 $ 72,867 Energy-marketing volumes (in thousands of equivalent Dth) 27,025 34,159 112,982 113,513 142,601 Natural gas-gathering volumes (MDth) For unaffiliated customers 21,778 20,291 84,961 72,908 57,586 For Questar Gas 9,853 8,237 32,050 29,893 28,506 For other affiliated customers 5,164 4,559 19,659 17,720 17,679 Total gathering 36,795 33,087 136,670 120,521 103,771 Gathering revenue (per Dth) $0.14 $0.16 $0.15 $0.16 $0.21
-13- Revenues Revenues from natural gas sales were 27% higher in 1999 compared with 1998. Gas production rose 22% and selling prices were 4% higher. First quarter revenues from selling natural gas increased $8.8 million as a result of a 17% increase in price and a 13% increase in volumes of gas produced. Production benefitted from a successful development drilling program and acquisition of Canadian producing properties in the first quarter of 2000. First quarter Canadian gas production grew 94% to 1.6 Bcf , while U.S. production increased 8% to 15.4 Bcf. The effect of gas imbalances on results of operations, liquidity, and capital resources is insignificant. Revenues from selling oil and natural gas liquids, excluding cost of service activities, climbed 8% in 1999 due to a 10% increase in average selling prices. A 103% increase in the average price of oil and NGL more than offset the effect of lower production to result in a 86% increase in first quarter revenues. Production of oil and NGL decreased in the first quarter as a result of selling nonstrategic properties in the fourth-quarter of 1999. Higher prices also benefitted the operations of liquids-extraction plants that experienced improved results for the first quarter of 2000. Revenues and product purchases for marketing activities both increased 4% in 1999 compared with 1998 resulting in no change in the margin year to year. In 1999, the Company received refunds from pipelines as a result of orders issued by FERC. Marketing volumes were unchanged year to year. While commodity prices increased during the first quarter of 2000, marketing volumes declined 21% due to decreased oil trading activity and the impact of unfavorable fixed transportation rates for natural gas. Revenues from gas gathering and processing grew 2% in 1999. Gathering volumes increased 13% because of increased drilling and gas production in the Rocky Mountain region. A change in the terms of the gathering contract with Questar Gas reduced the gathering rate from $.21 in 1997 to $.16 per Dth in 1998 and also resulted in a $3 million write-down of gathering assets in 1997 due to the projected reduction of gathering revenues. Volumes of gas gathered increased 11% in the first quarter of 2000, reflecting more production in the areas served by the Company. During 1999, QMR had forward sale contracts in place on approximately 59% of its gas production at an average price of $2.03 per Mcf, net back to the well. Approximately 56% of oil production, excluding cost of service oil production, was hedged at an average price of $15.02 per barrel, net back to the well, which was equivalent to $16.33 per barrel using the West Texas Intermediate benchmark. At December 31, 1999, approximately 52% of Company owned gas production in 2000 and 2001 was under hedging contracts with prices, net back to the well, between $2.15 and $2.23 per Mcf. Oil production in 2000 and 2001 is hedged at $17.22 to $17.67 per barrel, net back to the well, on approximately 84% of production, excluding cost of service production. As of the end of the first quarter 2000, about 40% of natural gas production through the end of 2001 is hedged at an average price of $2.15 per Mcf, net back to the well. Approximately 80% of oil production, excluding cost of service production, is hedged at an average price of $17.22 per barrel, net back to the well through the end of 2001. Expenses A 31% drop in the average selling price of oil and NGL caused a $31 million write-down of oil and gas properties in the fourth quarter of 1998 under full cost accounting rules. The write-down reduced income by $18.5 million after taxes. Revenues for QMR decreased 12% in 1998 compared with 1997, due primarily to lower marketing revenues and lower selling prices for oil and NGL. Natural gas production increased 8% primarily as a result of producing properties acquired in September 1998. Lower commodity prices in Canada caused a $6 million full cost write-down in 1997. Operating and maintenance expenses were higher in the three-month period of 2000 when compared with the 1999 period primarily because of increased investment in producing properties. The Company added approximately 61.1 Bcfe of reserves and 800 wells with the first quarter 2000 acquisition of Canor. Operating and maintenance expenses increased 8% in 1999 primarily due to an increase in the number of gas and oil properties. Production costs in aggregate increased 10% in 1999 compared with 1998, but were 6% lower on an equivalent Mcf basis. -14- The combined U.S. and Canadian full cost amortization rate was $.80 per Mcfe for the first quarter of 2000 compared with $.83 for the comparable 1999 quarter. The lower rate was due to successfully adding reserves through drilling and selling nonstrategic properties. Higher production volumes more than offset the lower amortization rates and resulted in increased amortization expense in the first quarter of 2000 when compared with the corresponding 1999 period. The full cost amortization rate decreased to $.80 per Mcfe for 1999, down from $.85 in 1998. However, depreciation and amortization expense increased 10% in 1999 because of higher gas production. QMR achieved a five-year average full cost finding and acquisition cost of $.90 per Mcfe in 1999 compared with $.95 per Mcfe in 1998. With respect to Wexpro's cost of service activities, the five-year finding cost was $.64 per Mcfe and $.80 per Mcfe in 1999 and 1998, respectively. Debt expense was $10.9 million, $12.6 million, and $17.4 million in 1997, 1998, and 1999, respectively. Debt expense was higher in 1999 and 1998 when compared with the corresponding prior year because of higher levels of borrowings used to finance capital expansion. Debt expense was higher in the first quarter of 2000 compared to the 1999 period primarily because of increased borrowing for capital expenditures. Effective income tax rates are below the combined federal, state and foreign statutory rate of about 40% primarily due to a portion of the Company's gas production qualifying for nonconventional fuel tax credits, which reduced income tax expense by $5.3 million in 1999, $5.7 million in 1998, and $6.6 million in 1997. The effective income tax rate for the first quarter was 32.8% in 2000 and 24.3% in 1999. The Company recognized $1.1 million of production-related tax credits in the first quarter of 2000 and $1.3 million in the first quarter of 1999. Operating Income and Net Income QMR's operating income and net income increased 36% and 32%, respectively, in 1999 compared with 1998, excluding a 1998 full cost write-down. Primary factors were an increase in gas production, higher commodity prices and an increase in the Wexpro investment base. QMR's operating income and net income rose 79% and 82%, respectively, in the first quarter of 2000 when compared with the first quarter of 1999, due primarily to increased production of natural gas and higher prices received for gas, oil and NGL. Other factors include higher earnings from Wexpro and gas gathering and processing operations. Wexpro's net income increased $.7 million to $5.8 million in the first quarter of 2000. Wexpro expanded its investment in development drilling prospects in response to higher regional demand. Wexpro's investment base, net of deferred income taxes, grew 12% to $108.9 million as of December 31, 1999, through its successful development drilling program. Wexpro's investment base represents the unamortized portion of the dollars invested in those assets that are regulated by the Wexpro settlement agreement. Wexpro's effective after-tax return on investment in those properties was 18.9% at the end of the year. A summary of the Wexpro settlement agreement is provided in Note 10 of the Notes to Consolidated Financial Statements under Item 13 of this Form 10. Gas gathering and processing and energy-marketing operations reported $.9 million in combined earnings for the first quarter of 2000 versus $.8 million a year ago. Volumes of gas gathered increased 11% in the first three months of 2000, reflecting more production in the areas served. Higher prices benefitted the operations of gas processing plants which experienced improved results for the first quarter of 2000. The plants extract and sell liquids from the natural gas stream. Increased commodity prices caused revenues from energy-marketing activities to be higher, but the impact of unfavorable fixed transportation rates and the settlement of gas imbalances resulted in an $841,000 after-tax loss for energy-marketing activities in the first quarter of 2000. Reserves Excluding activities with respect to cost of service related reserves, QMR achieved a 131% reserve replacement ratio in 1999. The reserve replacement ratio measures the extent to which annual oil and gas production volumes are replaced in the current year through -15- acquisitions, discoveries, development drilling, and revisions of prior estimates, less any sales of reserves that may have occurred. In 1999, reserve additions, revisions, and purchases amounted to 134 Bcfe with 108% of the reserve replacement ratio coming from drilling results and 23% from purchases. In 1999, QMR sold 34 Bcfe of nonstrategic reserves mostly in the Permian Basin and Kansas with combined daily production of 4.3 MMcf of gas and 1,100 barrels of oil. The sale proceeds helped reduce the full cost amortization rate in the fourth quarter of 1999. Reserve replacement in 1998 was 260% and 170 Bcfe, primarily the result of acquiring an estimated 150 Bcfe of proved oil and gas reserves, primarily in Oklahoma, as well as in Texas, Arkansas and Louisiana. The proved reserves associated with properties qualifying for nonconventional fuel credits are not dependent upon the existence of the income tax credits to be economically producible and are not a significant part of QMR's proved reserves. The expiration of these credits on December 31, 2002 is not expected to have a significant impact on future operations or proved reserves. Liquidity and Capital Resources - Operating Activities: Net cash provided from operating activities was derived from the following:
For the Three Months Ended March 31, For the Year Ended December 31, 2000 1999 1999 1998 1997 (In Thousands) Net Income $15,049 $ 8,253 $ 45,866 $ 16,162 $ 38,090 Non-cash transactions 20,581 20,053 90,077 100,106 77,132 Changes in working capital (4,498) 8,665 4,914 11,245 21,713 Net cash provided from operating activities $31,132 $36,971 $140,857 $127,513 $136,935
Net cash provided from operating activities in the first quarter of 2000 was $5.8 million less than was generated in the first quarter of 1999. A decrease in cash flow from changes in operating assets and liabilities as a result of payments made on hedging account margin calls and timing differences in payments of general accounts payable more than offset the effects of higher net income. Net cash provided from operating activities increased 10% in 1999 primarily due to higher net income. Cash flows from accounts receivable declined, representing increases in balances in 1999, due to higher commodity prices. The write-downs of oil and gas properties in both 1998 and 1997 and their effect on deferred income taxes were noncash transactions. Investing Activities: Capital expenditures and other investing activities amounted to $134.3 million in 1999, $254.5 million in 1998, and $92.3 million in 1997. Capital expenditures were $80.3 million in the first quarter of 2000, which includes approximately $61 million plus the assumption of $5.4 million in short-term debt for the purchase of Canor. In the first quarter of 1999, capital expenditures totaled $14.1 million. Following is a summary of capital expenditures for 1999 and 1998, and a forecast for 2000: -16-
Year Ended December 31, 2000 1999 1998 Forecast (In Thousands) Capital expenditures and other investing activities Exploratory drilling $ 2,800 $ 1,538 $ 5,898 Development drilling 83,500 64,642 60,402 Other exploration 7,800 19,464 6,789 Reserve acquisitions 66,900 3,704 158,000 Production 16,900 12,856 8,434 Gathering and processing 12,600 12,703 11,046 General and other 500 19,362 3,977 $191,000 $134,269 $254,546
Capital expenditures in 1999 were primarily comprised of exploration and development of gas and oil reserves and a $9.1 million equity contribution in a partnership that operates a liquids processing plant. QMR participated in drilling 235 wells (93 net wells) in 1999 that resulted in 167 gas wells, 10 oil wells, 19 dry holes and 39 wells in progress at year end. The 1999 drilling success rate was 90%. Financing Activities: Net cash flow provided from operating activities was sufficient to fund 1999 capital expenditures. The Company used the proceeds of long-term debt and collection of notes receivable to reduce short-term borrowings and refinance reserved-based, long-term debt used to acquire gas and oil reserves in 1998. Proceeds from a sale of nonstrategic gas and oil properties were placed in an escrow account pending a reinvestment in strategic-producing properties. In 1999, QMR entered into a long-term senior-revolving-credit facility with a syndication of banks. The credit facility currently has a $300 million capacity. QMR had outstanding $293.1 million and $264.9 million as of March 31, 2000 and December 31, 1999, respectively, under this arrangement. Net working capital was negative at March 31, 2000 and December 31, 1999, because of short-term borrowings. These borrowings are typical of a company expanding operations. In the first quarter of 2000, QMR financed capital expenditures, including the acquisition of Canor, through borrowings from Questar, from an existing long-term debt arrangement, and from net cash provided from operating activities. Debt balances owed to Questar as of March 31, amounted to $49.7 million in 2000 and $75.7 million in 1999, net of notes receivable from Questar. QMR intends to finance 2000 capital expenditures through net cash provided from operations, borrowings from Questar, and borrowings under QMR's existing long term credit facility. QMR's consolidated capital structure consisted of 41% long-term debt and 59% common shareholder's equity at December 31, 1999, and 42% long-term debt and 58% common shareholder's equity at March 31, 2000. Qualitative and Quantitative Disclosure about Market Risk - QMR's primary market-risk exposures arise from commodity-price changes for natural gas, oil and other hydrocarbons and changes in long-term interest rates. The Company has an investment in a Canadian operation that subjects it to exchange-rate risk. QMR also has reserved certain volumes of pipeline capacity for which it is obligated to pay $3 million annually for the next seven years, whether or not it is able to market the capacity to others. -17- Hedging Policy: We have established policies and procedures for managing market risks through the use of commodity-based derivative arrangements. Such arrangements include straight swaps (which fix a price for a specified expiration date and a specified quantity of product), costless collars (put options purchased by us matched to call options sold by us establishing a floor and ceiling price), and other contractual arrangements. A primary objective of these hedging transactions is to protect our product sales from adverse changes in energy prices. The volume of production hedged and the mix of derivative instruments employed are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by the Board of Directors. Additionally, under the terms of the Company's revolving credit facility, not more than 75% of the Company's production quantities can be committed to hedging arrangements. The Company does not enter into derivative arrangements for speculative purposes. Energy Price Risk Management: Energy-price risk is a function of changes in commodity prices as supply and demand fluctuate. QMR bears a majority of the risk associated with changes in commodity prices. The Company uses hedge arranagements in the normal course of business to limit the risk of adverse price movements; however, these same arrangements usually limit future gains from favorable price movements. At March 31, 2000, hedge contracts held by QMR covered price exposure for about 58.6 million Dth and 2.1 MMBbl of oil. QMR held hedge contracts covering the price exposure for about 72.1 million Dth of gas and 2.4 MMBbl of oil at December 31, 1999. A year earlier the contracts covered 45.3 million Dth of natural gas and 464,000 barrels of oil. The hedging contracts exist for a significant share of QMR owned gas and oil production and for a portion of gas-marketing transactions. Hedge contracts at March 31, 2000 and December 31, 1999, had terms extending through December 2001, with about 53% and 65%, respectively, expiring by the end of 2000. The mark-to-market adjustment of gas and oil price-hedging contracts at March 31, 2000, was a negative $31.5 million. A 10% decline in gas and oil prices would cause a positive $18.0 million mark-to-market adjustment resulting in a negative $13.5 million balance on that date. Conversely, a 10% increase in prices results in a $18.6 million negative mark-to-market adjustment resulting in a negative $50.2 million balance as of March 31, 2000. Comparatively, the mark-to-market adjustment of gas and oil price-hedging contracts at December 31, 1999, was a negative $6.2 million. A 10% decline in gas and oil prices would cause a positive $16.7 million mark-to-market adjustment resulting in a $10.5 million balance. A 10% increase in prices results in a $16.3 million negative mark-to-market adjustment resulting in a negative $22.5 million balance. The fair value of hedging contracts at December 31, 1998, was $6 million. A 10% decline in gas and oil prices would cause the fair value of the contracts to increase by $3.9 million. A 10% increase in prices results in a $4.1 million lower fair value calculation. The mark-to-market calculations used energy prices posted on the NYMEX for the indicated measurement dates. These sensitivity calculations do not consider changes in the fair value of the corresponding scheduled physical transactions (i.e., the correlation between the index price and the price to be realized for the physical delivery of gas or oil production), which should largely offset the change in value of the hedge contracts. Interest Rate Risk Management: The Company owed $293.1 million of variable-rate long term debt at March 31, 2000, $264.9 million at December 31, 1999, and $181.6 million at December 31, 1998. The book value of variable rate debt approximates its fair value. If interest rates change by 10%, interest costs would increase or decrease about $1.7 million in 1999 and $1.1 million in 1998, correspondingly. This sensitivity calculation does not represent the cost to retire the debt securities. Securities Available for Sale: Securities available for sale represent equity instruments traded on national exchanges. The value of these investments is subject to day to day market volatility. A 10% change in prices would either increase or decrease the value by $1.0 million at December 31, 1999 and $1.3 million at March 31, 2000. Foreign Currency Risk Management: The Company does not hedge the Canadian currency exposure of its Canadian operation's net assets. The net assets of the foreign operation were negative at December 31, 1999 and March 31, 2000. Long-term debt held by the foreign operation, amounting to $59.9 million (U.S.) at December 31, 1999 and $66.6 million (U.S.) at March 31, 2000, is expected to be repaid from future operations of the foreign company. As more fully described under "Item 3. Properties - Recent Developments" herein, QMR expanded its foreign operations during January 2000 when it purchased 100% of the outstanding common stock of Canor for approximately $61 million (U.S.) plus the assumption of $5.4 million (U.S.) of short-term debt. -18- Litigation - QMR, or one of its subsidiaries, is a party to various legal actions arising in the normal course of business. See "Item 8. Legal Proceedings." The Company regularly reviews potential liabilities related to legal proceedings and records appropriate accruals after considering estimates of the outcome of such matters and the Company's experience in contesting, litigating, and settling similar matters. On January 4, 2001, a district court judge in Oklahoma approved the settlement agreement in Bridenstine v. Kaiser-Francis Oil Company, a class action lawsuit that was originally filed against Questar E&P, other QMR affiliates and Questar, and unrelated defendants in 1995. Pursuant to the terms of the settlement, QMR and Union Pacific Resources Company (predecessor in interest to Questar E&P) paid $22.5 million ($16.5 million by QMR and $6 million by Union Pacific Resources) to resolve all issues pending against the settling defendants. Questar E&P has paid the settlement funds, which are being held in escrow pending the expiration of a 30-day appeal period following the entry of the judge's order. Payment of the settlement funds did not have a material adverse impact on QMR's financial results. While it is not currently possible to predict or determine the outcome of the various legal actions, it is the opinion of management that the outcomes will not have a material adverse effect on the Company's future results of operations, financial position, or liquidity. Year 2000 Issues - Questar established a team to address the issue of computer programs and embedded computer chips being unable to distinguish between the year 1900 and the year 2000 ("Y2K"). The team identified 55 projects among Questar and its affiliated companies that were assessed, remediated, tested, and determined to be completed. In the process, Questar employees contacted more than 8,000 vendors and suppliers to assess their readiness to meet obligations to Questar. The cost of the Y2K project was approximately $5.1 million and QMR's share of those costs was $.4 million. The Company did not experience a disruption of operations because of Y2K. Preparation for Y2K provided several benefits. The Company completed an inventory of its primary systems and a testing laboratory. Systems were tested and remediated where necessary. The testing laboratory will become an important part of the information-technology management. In response to the Y2K challenge, business contingency plans were revised and successfully tested. ITEM 3. PROPERTIES Reserves The following table sets forth the Company's estimated proved reserves, the 10% present value of the estimated future net revenues therefrom and the standardized measure of discounted net cash flows as of December 31, 1999. QMR's reserves were estimated by Ryder Scott Company, H. J. Gruy and Associates, Inc., Netherland, Sewell & Associates, Inc., Malkewicz Hueni Associates, Inc., and Gilbert Laustsen Jung Associates Ltd., independent petroleum engineers. The Company does not have any long-term supply contracts with foreign governments or reserves of equity investees or of subsidiaries with a significant minority interest. These proved reserve volumes do not include cost of service reserves managed and developed by Wexpro for Questar Gas. -19-
December 31, 1999 United States Canada Total Estimated proved reserves Natural gas (Bcf) 493.8 20.7 514.5 Oil and NGL (MMBbls) 11.1 2.8 13.9 Proved developed reserves (Bcfe) 471.4 32.5 503.9 Present value of estimated future net revenues before future income taxes discounted at 10% (in thousands) (1) $509,522 $48,568 $558,090 Standardized measure of discounted net cash flows (in thousands)(2) $402,771 $41,663 $444,434 _______
(1)Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and development costs (but excluding the effects of general and administrative expenses; debt service; depreciation, depletion and amortization; and income tax expense). (2)The standardized measure of discounted net cash flows prepared by the Company represent the present value of estimated future net revenues after income taxes, discounted at 10%. Estimates of the Company's proved reserves and future net revenues are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). Estimated quantities of proved reserves and future net revenues therefrom are affected by natural gas and oil prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating natural gas and oil reserves and their estimated values, including many factors beyond the control of the producer. The reserve data set forth in this document represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgement. As a result, estimates of different engineers, including those used by the Company, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing natural gas and oil prices, operating costs and other factors, which revisions may be material. Accordingly, reserve estimates are often different from the quantities of natural gas and oil that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. Reference should be made to Note 13 of the Notes to Consolidated Financial Statements included in Item 13 of this document for additional information pertaining to the Company's proved natural gas and oil reserves as of the end of each of the last three years. During 2000, the Company filed estimates of oil and gas reserves as of December 31, 1999, with the U. S. Department of Energy's Energy Information Administration ("EIA") on Form EIA-23. Reserve estimates filed on Form EIA-23 are based upon the same underlying technical and economic assumptions as the estimates of the Company's reserves included herein. However, the EIA requires reports to include the interests of all owners in wells that the Company operates and to exclude all interests in wells that the Company does not operate. -20- The following charts illustrate QMR's reserve statistics for the years ended December 31, 1995 through 1999:
Oil and Gas Reserves (Bcfe)* Year Year-End Reserves Annual Production Reserve Life (Years) 1995 311.3 42.5 7.3 1996 493.6 51.5 9.6 1997 469.3 61.7 7.6 1998 574.1 65.3 8.8 1999 597.6 76.6 7.8
* Does not include cost of service reserves managed and developed by Wexpro for Questar Gas.
Proportion of Proved Developed to Proved Reserves and Proportion of Gas Reserves (Bcfe)* Year Total Proved Proved Developed Developed Natural Gas Percentage of Reserves Reserves Percent of Total Proved Reserves 1995 311.3 293.8 94% 83% 1996 493.6 410.1 83% 78% 1997 469.3 392.9 84% 81% 1998 574.1 506.0 88% 85% 1999 597.6 503.9 84% 86%
* Does not include cost of service reserves managed and developed by Wexpro for Questar Gas. Geographic Diversity of Producing Properties The following table summarizes proved reserves by the Company's major operating areas at December 31, 1999:
Proved Reserves* % of Total (Bcfe) Mid-Continent 335.1 56.1% Rocky Mountain Region (exclusive of Pinedale) 139.7 23.3% Pinedale Anticline 54.7 9.2% Western Canada Sedimentary Basin 37.4 6.3% San Juan Basin 30.7 5.1% 597.6 100.0%
* Does not include cost of service reserves managed and developed by Wexpro for Questar Gas. -21- Production The following table sets forth the Company's net production volumes, the average sales prices per Mcf of gas, Bbl of oil and Bbl of natural gas liquids produced, and the production cost per Mcfe for the three months ended March 31, 2000 and 1999 and for the years ended December 31, 1999, 1998, and 1997, respectively:
Three Months Ended March 31, Year Ended December 31, 2000 1999 1999 1998 1997 United States (excluding cost of service activities) Volumes produced and sold Gas (Bcf) 15.4 14.2 59.8 48.6 44.3 Oil and NGL (MMBbls) .4 .5 1.9 1.9 2.1 Sales Prices: Gas (per Mcf) $ 2.20 $ 1.88 $ 2.02 $ 1.95 $ 1.92 Oil and NGL (per Bbl) $21.66 $10.70 $13.31 $12.41 $17.90 Production costs per Mcfe $ .62 $ .60 $ .59 $ .64 $ .65 Canada Volumes produced and sold Gas (Bcf) 1.6 .8 2.9 2.7 3.1 Oil and NGL (MMBbls) 0.2 0.1 0.4 0.4 0.3 Sales Prices: Gas (per Mcf) $ 1.90 $ 1.48 $ 1.61 $ 1.40 $ 1.35 Oil and NGL (per Bbl) $21.58 $10.47 $16.56 $14.09 $16.80 Production costs per Mcfe $ .72 $ .61 $ .67 $ .58 $ .52
-21- Productive Wells The following table summarizes the Company's productive wells, including productive cost of service wells included in Wexpro's investment base, as of December 31, 1999:
Productive Wells (1) (2) (3) Gas Wells Oil Wells Total Wells Gross Net Gross Net Gross Net United States 3,228 1,220.1 1,249 484.5 4,477 1,704.6 Canada 82 22.3 92 27.2 174 49.5 Total: 3,310 1,242.4 1,341 511.7 4,651 1,754.1 ____________
(1) Although many of the Company's wells produce both oil and gas, a well is categorized as either an oil well or a gas well based upon the ratio of oil to gas production. (2) Each well completed to more than one producing zone is counted as a single well. There were 134 gross wells with multiple completions. (3) Wexpro's investment base represents the dollars invested in development drilling on cost of service properties that are regulated by the Wexpro settlement agreement. A summary of the Wexpro settlement agreement is provided in Note 10 of the Notes to Consolidated Financial Statements under Item 13 herein. The Company also held numerous overriding royalty interests in gas and oil wells, a portion of which are convertible to working interests after recovery of certain costs by third parties. After converting to working interests, these overriding royalty interests will be included in the Company's gross and net well count. -22- Leasehold Acreage The following table summarizes developed and undeveloped leasehold acreage in which the Company owns a working interest as of December 31, 1999. "Undeveloped Acreage" includes (i) leasehold interests that already may have been classified as containing proved undeveloped reserves; and (ii) unleased mineral interest acreage owned by the Company. Excluded from the table is acreage in which the Company's interest is limited to royalty, overriding royalty, and other similar interests.
Leasehold Acreage - December 31, 1999 Developed (1) Undeveloped (2) Total Gross Net Gross Net Gross Net United States Arizona - - 480 450 480 450 Arkansas 37,729 16,569 8,984 4,478 46,713 21,047 California 80 28 35,011 15,322 35,091 15,350 Colorado 176,604 123,974 207,853 105,449 384,457 229,423 Idaho - - 44,175 10,643 44,175 10,643 Illinois 172 39 14,307 3,997 14,479 4,036 Indiana - - 1,621 467 1,621 467 Kansas 134 134 7,761 2,471 7,895 2,605 Kentucky - - 14,461 5,468 14,461 5,468 Louisiana 15,246 9,992 251 251 15,497 10,243 Michigan - - 6,200 1,266 6,200 1,266 Minnesota - - 313 104 313 104 Mississippi 25,706 21,408 - - 25,706 21,408 Montana 25,445 10,707 319,588 58,438 345,033 69,145 Nevada 320 280 680 543 1,000 823 New Mexico 92,497 68,188 31,765 9,313 124,262 77,501 North Dakota 1,333 375 145,841 21,580 147,174 21,955 Ohio - - 202 43 202 43 Oklahoma 1,570,227 294,207 52,736 33,296 1,622,963 327,503 Oregon - - 43,869 7,671 43,869 7,671 South Dakota - - 204,558 107,988 204,558 107,988 Texas 167,690 60,170 50,571 39,515 218,261 99,685 Utah 45,712 35,001 109,180 43,818 154,892 78,819 Washington - - 26,631 10,149 26,631 10,149 West Virginia 969 115 - - 969 115 Wyoming 216,991 138,681 445,315 271,418 662,306 410,099 Total U.S. 2,376,855 779,868 1,772,353 754,138 4,149,208 1,534,006 Canada Alberta 42,080 11,910 61,760 18,541 103,840 30,451 British Columbia 34,259 8,855 39,169 22,977 73,428 31,832 Total Canada 76,339 20,765 100,929 41,518 177,268 62,283 Total Acreage 2,453,194 800,633 1,873,282 795,656 4,326,476 1,596,289
-23- (1) Developed acres are acres spaced or assignable to productive wells. (2) Undeveloped acreage is leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves. Of the aggregate 1,873,282 gross and 795,656 net undeveloped acres, 123,501 gross and 36,105 net acres are held by production from other leasehold acreage. Substantially all the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing leases are renewed or production has been obtained from the acreage subject to the lease prior to that date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net acres subject to leases summarized in the preceding table that will expire during the periods indicated:
Acres Expiring Gross Net Twelve Months Ending: December 31, 2000 91,504 39,918 December 31, 2001 96,177 31,322 December 31, 2002 39,971 13,082 December 31, 2003 95,043 52,366 December 31, 2004 and later 1,550,587 658,968
Drilling Activity The following table summarizes the number of development and exploratory wells drilled by the Company, including cost of service development drilling conducted by Wexpro, during the years indicated.
Year Ended December 31, 1999 1998 1997 Gross Net Gross Net Gross Net Development Wells United States: Completed as natural gas wells 159 78.4 105 54.6 82 27.4 Completed as oil wells 5 2.4 29 1.0 64 6.6 Dry holes 15 6.1 12 3.7 18 5.7 Waiting on completion 29 - 13 - 26 - Drilling 6 - 9 - 15 - Canada: Completed as natural gas wells 7 1.2 4 0.9 4 0.9 Completed as oil wells 5 1.9 12 4.0 4 1.3 Dry holes 2 1.3 4 1.2 3 0.9 Waiting on completion 2 - 2 - 6 - Drilling - - 1 - 2 - Total Development Wells 230 91.3 191 65.4 224 42.8
-24-
Exploratory Wells United States: Completed as natural gas wells 1 0.2 5 1.6 4 1.6 Completed as oil wells - - 1 .6 - - Dry holes 2 1.1 4 1.4 1 0.3 Waiting on completion 1 - - - 2 - Drilling 1 - - - - - Canada: Completed as natural gas wells - - - - 1 - Completed as oil wells - - 1 .3 2 0.1 Dry holes - - 3 1.4 - 0.7 Waiting on completion - - - - 1 - Total Exploratory Wells 5 1.3 14 5.3 11 2.7 Total Wells 235 92.6 205 70.7 235 45.5
Operation of Properties The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions. The charges under operating agreements customarily vary with the depth and location of the well being operated. QMR is the operator of approximately 50% of its wells. As operator, QMR receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged in the area to or by unaffiliated third parties. In presenting its financial data, QMR records the monthly overhead reimbursement as a reduction of general and administrative expense, which is a common industry practice. Title to Properties Title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and gas industry, liens for current taxes not yet due and, in some instances, to other encumbrances. The Company believes that such burdens do not materially detract from the value of such properties or from the respective interests therein or materially interfere with their use in the operation of the business. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Investigations, generally including a title opinion of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Pinedale Anticline Project - In January 2000, Questar E&P and Wexpro completed a high-volume producing well in the Company's Pinedale Anticline development in Sublette County, Wyoming. The Mesa Unit No. 3 produced 11.4 MMCF of natural gas into a pipeline and 113 barrels of oil from the Lance Formation during the initial 24-hour period. The Lance Formation in the Pinedale Anticline area is a geologic structure comprised of many discrete sandstone intervals found at depths between 8,500 and 13,500 feet. The Mesa Unit No. 3 was drilled to a total measured depth of 13,055 feet and was fracture-stimulated (a production enhancement technique) in 11 individual sandstone intervals. Questar E&P and Wexpro have a combined 93.8% working interest in the well. While this is not a new discovery -- the first test well into the Pinedale Anticline was drilled in 1939 and Questar drilled its first acreage holding well in this area in 1963 - it has only been recently that improvements in well completion and production enhancement technology has provided the means to attain higher production rates from multiple sand intervals such as the Lance Formation at a reasonable cost. The Company has completed a second Mesa Unit well - No. 6 - located about one-half mile south of the Mesa Unit No. 3. The second well encountered a similar number of potentially productive sandstone intervals, and initial test results are comparable to the Mesa Unit No. 3. A third well failed to produce economic quantities of gas because of lower-quality reservoir rock. The Bureau of Land Management ("BLM") subsequently suspended drilling activity on the Pinedale Anticline pending completion of an Environmental Impact Statement. As of June 30, 2000, there were eight proved developed producing wells on the Company's acreage in the Pinedale area. Malkewicz Hueni Associates, Inc., independent petroleum engineers, have identified an additional 28 proved undeveloped locations, based on SEC definitions and guidelines, on the Company's acreage. The gross reserve range for the proved developed wells was 3.1 to 7.5 Bcfe and the gross reserve range for the proved undeveloped locations was 3.1 to 6.4 Bcfe. An average completed well cost of $2,350,000 was assumed for the proved undeveloped locations. Questar E&P and Wexpro have an approximate 60 percent working interest in 14,800 gross acres in the Mesa Area of the Pinedale Anticline. Based on wells physically spaced on 80 acres, which is less dense than the 40-acre spacing currently permitted by the State of Wyoming in analogous reservoirs, the Company estimates the potential for 130 or more drilling locations within the Company's acreage in the Pinedale Anticline. On July 27, 2000, the Wyoming State Office of the BLM issued its Record of Decision ("ROD") approving the Pinedale Anticline natural gas project under the Resource Protection Alternative of its Environmental Impact Statement, as modified. The ROD allows 700 producing well pads in the area, which encompasses approximately 197,000 acres, including the Company's acreage, and does not restrict the number of drilling rigs to be employed. The Company immediately began employing five contract drilling rigs to drill the first five wells of an 8 to 10 well program planned for the remainder of 2000. The accelerated rate of drilling activity was necessary in order to complete the drilling program prior to being required to cease drilling activity due to winter wildlife habitat restrictions. On December 7, 2000, Questar reported information on nine additional wells drilled by the Company in the Pinedale Anticline. Five of the nine wells were completed with initial flow rates ranging from 7.5 MMcf per day to 10.2 MMcf per day. The wells were fracture-stimulated in between 6 and 11 individual sandstone intervals, and the low rates reflected only completed intervals. A sixth well was completed in only two fracture- stimulated intervals due to BLM imposed winter restrictions and had an initial daily flow rate of 2.6 MMcf per day. The remaining three wells have reached total depth, but completion efforts will be delayed until 2001 because of the winter activity restictions. The drilling results and initial production from these new wells are in line with expectations for the area. Average completed well cost for the six wells was $2.2 million, also in line with the Company's Projections. At December 31, 2000, the six completed wells were producing into the pipeline. Additional data will be gathered from these wells and the existing producing wells to determine any changes in the Company's 2001 Pinedale Anticline drilling program, for which it is now seeking permits. See the Company's current report on Form 8-K dated December 7, 2000. Recognizing that some flow rates are currently constrained by the capacity of surface production facilities, it is estimated that gross production on December 31, 2000, from 14 company-operated Pinedale Anticline wells was approximately 26 MMcf of natural gas and 45 barrels of oil per day. The Company hs pre-sold its Pinedale Anticline production through February 2001 at an average price of $7.50 per Mcf (after gathering charges). At that price, the wells would pay out drilling and completion costs in a period of approximately four months. -26- Acquisitions and Dispositions of Properties Canadian Acquisition - On January 26, 2000, the Company completed the acquisition of all of the outstanding shares of Canor Energy Ltd., an oil and gas exploration company based in Calgary, Alberta, Canada. Canor owns and/or operates more than 800 wells located primarily in the province of Alberta, as well as in the provinces of British Columbia and Saskatchewan. The combination of Canor with Celsius Ltd. expands the Company's reported proved reserves by approximately 61.1 Bcfe, or 10%, and adds about 150,000 net acres to the Company's Canadian undeveloped leasehold inventory, principally in the province of Alberta. The purchase price for the cash transaction was approximately $61 million (U.S.) plus the assumption of $5.4 million (U.S.) of short-term debt. The Canor acquisition will provide a broader operating and financial base for the Company's Canadian activities, particularly in the areas of exploration and exploitation opportunities. It is anticipated that Celsius Ltd. and Canor will be amalgamated into a single entity at some point in the future. Disposition of Non-Strategic Properties - Questar E&P and Questar Gas Management have recently entered into agreements to sell working interests in oil and gas producing properties in Oklahoma and northern Texas and a gas-gathering system in Oklahoma to Chesapeake Energy Corporation. The transaction includes working interests in approximately 290 properties with a combined current net production of approximately 4.3 MMcf of gas and 180 Bbls of oil per day. The combined purchase price is $27 million, with closing scheduled to occur in January 2001. The properties being sold do not have long-term strategic importance to QMR and the sale will improve operating efficiency. The transaction will be recognized in 2001 upon closing. Office Leases Questar E&P and Wexpro lease office space under a sublease from Questar for its corporate headquarters at 180 East 100 South, Salt Lake City, Utah 84145. The Company also leases regional office space at various locations in the United States and Canada. For information concerning the Company's lease obligations, see Note 7 of the Notes to Consolidated Financial Statements appearing elsewhere in this Form 10. ITEM 4. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT All of the outstanding shares of common stock ($1.00 par value per share) of QMR are owned by Questar, whose principal executive offices are located at 180 East 100 South, Salt Lake City, Utah 84111. Questar possesses sole voting and investment power with respect to such shares of common stock. ITEM 5. DIRECTORS AND EXECUTIVE OFFICERS The executive officers and directors of the Company are set forth in the following table: Name Position Age R. D. Cash Chairman 58 G. L. Nordloh Presient, CEO and Director 53 S. E. Parks Vice President, Treasurer & CFO 49 M. B. McGinley Vice President 52 M. L. Owen Vice President, Administrative Services 49 C. C. Holbrook Secretary 54 Teresa Beck Director 46 P. J. Early Director 67 C. M. Heiner Director 62 W. N. Jones Director 74 -27- R. D. Cash, 58, Chairman of the Board of Directors, Questar (May 1985); President and Chief Executive Officer and Director, Questar (since 1977); Chairman of the Boards of Directors, all Questar affiliates (other than Questar Energy Trading); President and Chief Executive Officer, QMR (from April 1982 to August 1998). Mr. Cash also serves as a Director of Zions Bancorporation and Associated Electric and Gas Insurance Services Limited. He is a member of the Board of Directors of the Federal Reserve Bank (Salt Lake City Branch) of San Francisco and is a Trustee of the Salt Lake Organizing Committee for the Olympic Winter Games of 2002. Gary L. Nordloh, 53, President and Chief Executive Officer, QMR (August 1998) and all subsidiaries (commencing at various times beginning in March 1991); Vice President, QMR (May 1996 to August 1998); Executive Vice President, Questar (February 1996); Senior Vice President, Questar (March 1991 to February 1996); Director, Questar (October 1996); Director, QMR (May 1991), and all QMR subsidiaries (various times beginning in June 1989). Prior to joining the Questar organization in 1984, Mr. Nordloh was Vice President of Engineering and Operations for Hamilton Brothers Petroleum for three years and Division Engineering Manager (and various other assignments) for Amoco Production Company for nine years. Mr. Nordloh received a bachelor's degree in Petroleum Engineering from the Colorado School of Mines. He serves on the Board of Directors of Mountain States Legal Foundation; is Past-President of Rocky Mountain Oil and Gas Association (1995-1997); a member of the Society of Petroleum Engineers since 1974; is Past-President of the Society of Petroleum Engineers (Denver Section); and served as a Regional Vice President of the Independent Petroleum Association of America from 1989 to 1995. S. E. Parks, 49, Vice President, Treasurer and Chief Financial Officer, Questar and all affiliates except Questar Energy Trading (February 1996); Treasurer, Questar and affiliates (at various dates beginning in May 1984); Director, Questar E&P (May 1996). Mr. Parks received a B.A. degree in Accounting and a M.B.A. degree in Finance from the University of Utah. Since joining Questar in 1974, he has held a variety of management positions in the auditing, accounting and financial areas. Prior to joining Questar, Mr. Parks was with the Academic and Financial Planning Department of the University of Utah. M. B. McGinley, 52, Vice President, QMR (August 1998) and all subsidiaries (various dates beginning in February 1990); General Manager, Questar Energy Trading (October 1995) and Questar Gas Management (July 2000); Director, Questar Energy Trading (August 1998). Mr. McGinley has worked for various Questar affiliates for 31 years in a variety of engineering and marketing assignments. He holds a Bachelor of Science Degree in Chemical Engineering and a Master of Science Degree in Mechanical Engineering from the University of Utah. He is a registered professional engineer in Utah and Colorado and a member of the Independent Petroleum Association of America, and Rocky Mountain Oil and Gas Association and the Pacific Coast Gas Association. M. L. Owen, 49, Vice President, Administrative Services, QMR (August 1998) and all subsidiaries (various dates beginning in April 1989); Director, Questar Energy Trading (August 1998). Mr. Owen has been associated with QMR since its acquisition of Universal Resources Corporation in 1987. From 1982 to 1989, he served as Treasurer of Universal Resources. Prior to joining Universal Resources, Mr. Owen was employed with Arthur Andersen & Co. for eight years with various duties, including Audit Manager. He is a Certified Public Accountant, receiving his Accounting degree from Texas Tech University. Mr. Owen is a member of the Independent Petroleum Association of America and the Utah Association of Certified Public Accountants. C. C. Holbrook, 54, General Counsel, Questar (March 1999); Vice President Questar (October 1984); Corporate Secretary, Questar and all affiliates except Questar Energy Trading (various dates beginning in March 1982); Director, Questar E&P and Questar Gas Management (various dates beginning in May 1985). Teresa Beck, 46, Director, Questar (October 1999); Director, QMR (October 1999). Ms. Beck was President of American Stores from 1998 to 1999. She also served as American Stores' Chief Financial Officer from 1993 to 1998. She serves as a Director of Textron, Inc. and Albertson's Inc. and is a Trustee of Intermountain Health Care, Inc., The Children's Center, and the Salt Lake Organizing Committee for the Olympic Winter Games of 2002. P. J. Early, 67, Director, QMR (August 1995); Director, Questar (August 1995). Mr. Early served as Vice Chairman of Amoco Corporation from July of 1992 until his retirement in April 1995. He was also a Director of Amoco Corporation from 1989 to his retirement. He is a member of the Board of Trustees of the Museum of Science and Industry in Chicago. -28- Clyde M. Heiner, 62, Chief Operating Officer, Consonus, Inc., a Questar affiliate (August 2000); Senior Vice President, Questar (May 1984 to June 2000); President and Chief Executive Officer, Questar InfoComm (February 1993 to June 2000); Director, QMR (May 1984). W. N. Jones, 74, Director, QMR (May 1989); Senior Director, Questar (May 1998); Director, Questar (May 1981 to May 1998). Mr. Jones is Chairman of the Board, Lite Touch Inc., and a Trustee of Intermountain Health Care, Inc. ITEM 6. EXECUTIVE COMPENSATION Omitted. ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Omitted. ITEM 8. LEGAL PROCEEDINGS At December 31, 1999, Questar E&P, as well as other QMR affiliates and Questar, were among the named defendants in a class action lawsuit commenced in 1995 involving royalty payments in Oklahoma state court for Texas County, Oklahoma. In Bridenstine vs. Kaiser-Francis Oil Company, the plaintiffs alleged various fraud and contract claims against all defendants for a 17-year period. While this litigation did not specify the amount of damages being claimed, estimates at times were in excess of $80 million, plus punitive damages. The plaintiffs' primary claim alleges that a transportation fee charged against royalty payments was improper or excessive. The claims involved wells connected to an intrastate pipeline system that Questar Gas Management presently owns and operates. The suit also alleged claims for mismeasurement of gas and failure to market the gas for the "best available price." Kaiser-Francis and Questar E&P are the major working interest owners and operators of a majority of the wells connected to this pipeline system. QMR disputes plaintiffs' claims. On January 4, 2001, a district court judge in Texas County, Oklahoma, approved the settlement agreement reached by QMR and Union Pacific Resources Company (predecessor in interest to Questar E&P) in Bridenstine v. Kaiser-Francis Oil Company. Under the terms of the settlement, QMR and Union Pacific Resources paid $22.5 million ($16.5 million by QMR and $6 million by Union Pacific Resources) to resolve all of the issues pending against QMR in the litigation. Questar E&P has paid the settlement funds, which are being held in escrow bpending the expiration of a 30-day appeal period following the entry of the judge's order. Payment of the settlement funds did not have a material adverse impace on QMR's financial results. At December 31, 1999, Questar E&P was a defendant in a case styled Greghol Limited Partnership vs. Universal Resources Corporation, filed in Oklahoma state court, which was originally asserted as a statewide class action raising issues relative to calculation of royalties, and whether such calculations should reflect deductions for certain post-production costs. Relief sought by the plaintiff was unspecified. The Court has sustained Questar E&P's motion to de-certify the class. Questar E&P disputes these claims. In August 2000, plaintiff voluntarily dismissed the case without prejudice. In United States ex rel. Grynberg v. Questar Corp., et al., each of Questar Gas Management, Wexpro and Universal Resources Corporation d/b/a Questar Energy Trading Company are named as defendants in a case involving allegations of gas mismeasurement and of improper royalty valuations. The plaintiff filed on behalf of the federal government to recover underpaid royalties under the False Claims Acts, and the Department of Justice declined to intervene. Relief sought by the plaintiff is unspecified. This case and 75 substantially similar cases filed by the plaintiff have been consolidated for discovery and pre-trial rulings in Wyoming's federal district court. Motions to dismiss have been filed. The QMR subsidiaries dispute these claims. Questar Energy Trading and Questar Gas Management, two of the Company's wholly owned subsidiaries, have been added as defendants in a lawsuit filed by Jack Grynberg, an independent producer, pending in a Utah state district court (Grynberg v. Questar Pipeline Company). The lawsuit was originally filed against Questar Pipeline Company, an affiliate of the Company in Questar's Regulated Services unit, in -29- September of 1999. It alleges that the Questar defendants mismeasured gas volumes attributable to his working interest from a property in southwestern Wyoming. The plaintiff cites mismeasurement to support claims for breach of contract, negligent misrepresentation, fraud, breach of fiduciary responsibilities and alleges damages of $27 million. The Questar defendants have filed a comprehensive motion to dismiss the complaint on several grounds including expiration of the applicable statute of limitations, no basis for independent tort claims, and federal preemption. In Quinque Operating Company v. Gas Pipelines, et al., each of Questar Gas Management, Wexpro and Universal Resources Corporation (now known as Questar E&P) is named as a defendant in a lawsuit involving allegations of mismeasurement of natural gas resulting in underpayment of royalties to private and state lessors. Relief sought by the plaintiff is unspecified. Plaintiffs have asked that the case be certified as a nationwide class action. The case was removed from state to federal court and a motion to remand is pending. There are over 220 defendants. The QMR subsidiaries dispute these claims. Royalty class actions such as Quinque are being asserted in numerous states against other companies in the oil and gas production and marketing businesses in which QMR's subsidiaries participate. Accordingly, QMR expects similar royalty class actions to be filed in other states in which it has significant production and marketing activities such as Wyoming and Colorado, although such actions have not yet been filed and are not currently threatened. There are various other legal proceedings against subsidiaries of QMR. The Company regularly reviews potential liabilities related to legal proceedings and records accruals after considering estimates of the outcome of such matters and our experience in contesting, litigating, and settling similar matters. While it is not currently possible to predict or determine the outcomes of the various legal proceedings against QMR, it is the opinion of management that the outcomes will not have a material adverse effect on the Company's future results of operations, financial position or liquidity. Also see Note 7 of the Notes to Consolidated Financial Statements under Item 13 of this Form 10. ITEM 9. MARKET PRICE OF AND DIVIDENDS OF THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The common stock of the Company is owned entirely by Questar and, therefore, there is no trading of the Company's stock. Dividends of $4.3 million, $16.6 million, $15.9 million, and $16.3 million were declared and paid during the three months ended March 31, 2000, and the years ended December 31, 1999, 1998 and 1997, respectively. See Note 4 of the Notes to Consolidated Financial Statements under Item 13 of this Form 10 regarding restrictions as to dividend availability. ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES There have been no sales of unregistered securities by the Company. ITEM 11. DESCRIPTION OF REGISTRANT'S SECURITIES TO BE REGISTERED The following description of the capital stock of the Company and certain provisions of the Company's Amended Articles of Incorporation and Bylaws is a summary and is qualified in its entirety by the provisions of the Amended Articles of Incorporation and Bylaws, which have been filed as exhibits to this Form 10. -30- The Company has authorized twenty-five million (25,000,000) shares of Common Stock with a par value of $1.00 per share. All outstanding shares of stock are held by Questar Corporation. No preferred stock has been issued or authorized. Each common shareholder of record is entitled to one vote, by person or by proxy for each share of Common Stock held on every matter properly submitted to the stockholders for a vote. Except as otherwise provided by law or in the Amended Articles of Incorporation or Bylaws, stockholder votes are decided by a majority vote of the outstanding shares. ITEM 12. INDEMNIFICATION OF DIRECTORS AND OFFICERS Reference is made to Section 16-10a-901 through 16-10a-909 of the Utah Revised Business Corporation Act, which provides for indemnification of directors and officers in certain circumstances. The Bylaws provide that the Company may voluntarily indemnify any individual made a party to a proceeding because he is or was a director, officer, employee or agent of the Company against liability incurred in the proceeding, but only if the Company has authorized the payment in accordance with the applicable statutory provisions of the Utah Revised Business Corporation Act (Sections 16-10a-902, 16-10a-904 and 16-10a-907) and a determination has been made in accordance with the procedures set forth in such provision that such individual conducted himself in good faith, that he reasonably believed his conduct, in his official capacity with the Company, was in its best interests and that his conduct, in all other cases, was at least not opposed to the Company's best interests, and that he had no reasonable cause to believe his conduct was unlawful in the case of any criminal proceeding. The foregoing indemnification in connection with a proceeding by or in the right of the Company is limited to reasonable expenses incurred in connection with the proceeding, which expenses may be advanced by the Company. The Company's Bylaws provide that the Company may not voluntarily indemnify a director, officer, employee or agent of the Company in connection with a proceeding by or in the right of the Company in which such individual was adjudged liable to the Company or in connection with any other proceeding charging improper personal benefit to him, whether or not involving action in his official capacity, in which he was adjudged liable on the basis that personal benefit was improperly received by him. The Bylaws provide further that the Company shall indemnify a director, officer, employee or agent of the Company who was wholly successful, on the merits or otherwise, in defense of any proceeding to which he was a party because he is or was such a director, officer, employee or agent, against reasonable expenses incurred by him in connection with the proceeding. The Bylaws further provide that no director of the Company shall be personally liable to the Company or its stockholders for monetary damages for any action taken or any failure to take any action, as a director, except liability for (a) the amount of a financial benefit received by a director to which he is not entitled; (b) an intentional infliction of harm on the Company or the shareholders; (c) for any action that would result in liability of the director under the applicable statutory provision concerning unlawful distributions; or (d) an intentional violation of criminal law. Questar, the Company's parent, maintains an insurance policy on behalf of the officers and directors of the Company pursuant to which (subject to the limits and limitations of such policy) the officers and directors are insured against certain expenses in connection with the defense of actions or proceedings, and certain liabilities which might be imposed as a result of such actions or proceedings, to which any of them is made a party by reason of being or having been a director or officer. -31- ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Index to Consolidated Financial Statements and Supplementary Data Page Financial Statements - Report of Independent Auditors 33 Consolidated Statements of Income for the years ended December 31, 1999, 1998 and 1997 and for the three months ended March 31, 2000 (unaudited) and 1999 (unaudited) 34 Consolidated Balance Sheets at December 31, 1999 and 1998 and March 31, 2000 (unaudited) 35 Consolidated Statements of Shareholder's Equity for the years ended December 31, 1999, 1998 and 1997 and for the three months ended March 31, 2000 (unaudited) 37 Consolidated Statements of Cash Flows for the years ended December 31, 1999, 1998, and 1997 and for the three months ended March 31, 2000 (unaudited) and 1999 (unaudited) 38 Notes to Consolidated Financial Statements 39 Supplementary Data - Oil and Gas Producing Activities (Note 13 to Consolidated Financial Statements) 54 -32- Report of Independent Auditors Board of Directors Questar Market Resources, Inc. We have audited the accompanying consolidated balance sheets of Questar Market Resources, Inc. and subsidiaries as of December 31, 1999, and 1998, and the related consolidated statements of income and common shareholder's equity and cash flows for each of the three years in the period ended December 31, 1999. 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 consolidated financial position of Questar Market Resources, Inc. and subsidiaries at December 31, 1999, and 1998, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. /s/ Ernst & Young LLP Ernst & Young LLP Salt Lake City, Utah February 7, 2000 -33- QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS)
For the Three Months For the Year Ended March 31, Ended December 31, 2000 1999 1999 1998 1997 (Unaudited) REVENUES From unaffiliated customers $119,471 $94,643 $418,603 $382,791 $451,233 From affiliates 22,290 21,203 79,708 75,481 72,407 TOTAL REVENUES 141,761 115,846 498,311 458,272 523,640 OPERATING EXPENSES Natural gas and other product purchases 63,893 56,392 239,201 230,462 291,851 Operating and maintenance 22,918 20,169 79,916 73,763 72,958 Depreciation and amortization 20,977 19,605 78,608 71,377 67,078 Write-down of full cost oil and gas properties 31,000 6,000 Write-down of gas gathering properties 3,000 Other taxes 7,314 5,128 21,516 24,988 25,569 Wexpro settlement agreement - oil income sharing 984 209 2,292 1,053 2,347 TOTAL OPERATING EXPENSES 116,086 101,503 421,533 432,643 468,803 OPERATING INCOME 25,675 14,343 76,778 25,629 54,837 INTEREST AND OTHER INCOME 1,093 847 4,272 3,638 5,854 INCOME (LOSS) FROM UNCONSOLIDATED AFFILIATES 999 (31) 763 (930) (288) DEBT EXPENSE (5,370) (4,263) (17,363) (12,631) (10,882) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 22,397 10,896 64,450 15,706 49,521 INCOME TAX EXPENSE (CREDIT) 7,348 2,643 18,584 (1,019) 10,410 INCOME FROM CONTINUING OPERATIONS 15,049 8,253 45,866 16,725 39,111 DISCONTINUED OPERATIONS - QUESTAR ENERGY SERVICES, NET OF INCOME TAXES OF $347 IN 1998 AND $631 IN 1997 (563) (1,021) NET INCOME $15,049 $8,253 $45,866 $16,162 $38,090
See accompanying notes to consolidated financial statements. -34-
QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS) ASSETS As of March 31, As of December 31, 2000 1999 1998 (Unaudited) CURRENT ASSETS Cash and cash equivalents $ 2,206 $ 1,894 Notes receivable from Questar $ 4,000 25,100 Accounts receivable, net of allowance of $1,321 in 2000, $1,350 in 1999, and $3,253 in 1998 71,097 64,364 61,833 Accounts receivable from affiliates 11,962 11,459 11,359 Inventories, at lower of average cost or market - Gas and oil storage 2,699 8,863 8,892 Materials and supplies 2,421 2,390 1,893 Prepaid expenses and deposits 5,806 4,452 4,369 TOTAL CURRENT ASSETS 96,191 95,528 115,340 PROPERTY, PLANT AND EQUIPMENT Oil and gas properties, on the basis of full cost accounting - Proved properties 1,009,167 943,349 918,237 Unproved properties, not being amortized 87,138 69,777 62,487 Support equipment and facilities 16,370 13,408 14,878 Cost of service oil and gas properties, on the basis of successful efforts accounting 318,882 318,451 297,809 Gathering, processing and marketing 125,204 124,691 119,230 1,556,761 1,469,676 1,412,641 Less: Allowances for depreciation and amortization Oil and gas properties, on the basis of full cost accounting 563,123 554,491 498,718 Cost of service oil and gas properties, on the basis of successful efforts accounting 183,914 180,867 168,236 Gathering, processing and marketing 54,180 53,337 50,175 801,217 778,695 717,129 NET PROPERTY, PLANT AND EQUIPMENT 755,544 690,981 695,512 INVESTMENT IN UNCONSOLIDATED AFFILIATES 14,225 13,301 3,673 OTHER ASSETS - Note 3 52,374 48,081 628 $918,334 $847,891 $815,153
-35- LIABILITIES AND SHAREHOLDER'S EQUITY (IN THOUSANDS)
As of March 31, As of December 31, 2000 1999 1998 (Unaudited) CURRENT LIABILITIES Checks outstanding in excess of cash balances $ 1,246 Notes payable to Questar $ 49,700 24,500 $121,800 Accounts payable and accrued expenses Accounts and other payables 64,157 67,385 63,272 Accounts payable to affiliates 2,244 2,952 2,414 Federal income taxes 8,267 6,232 6,105 Other taxes 16,980 14,266 13,661 Accrued interest 2,344 1,443 1,044 TOTAL CURRENT LIABILITIES 143,692 118,024 208,296 INVESTMENT IN DISCONTINUED OPERATIONS - Questar Energy Services 1,905 LONG-TERM DEBT 293,074 264,894 181,624 DEFERRED INCOME TAXES 66,080 59,936 52,113 OTHER LIABILITIES 13,051 14,674 11,577 MINORITY INTEREST 2,882 2,529 COMMITMENTS AND CONTINGENCIES - Note 7 SHAREHOLDER'S EQUITY Common stock - par value $1 per share; authorized 25,000,000 shares; issued and outstanding 4,309,427 shares 4,309 4,309 4,309 Additional paid-in capital 116,027 116,027 116,027 Retained earnings 281,112 270,388 239,217 Other comprehensive income (loss) (1,893) (2,890) 85 399,555 387,834 359,638 $918,334 $847,891 $815,153
See accompanying notes to consolidated financial statements. -36- QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY (IN THOUSANDS)
Additional Other Common Paid-in Retained Comprehesive Comprehensive Stock Capital Earnings Income Income Balance at January 1, 1997 $4,309 $116,027 $217,190 ($181) Net income 38,090 $38,090 Cash dividends (16,325) Foreign currency translation adjustment, net of income taxes of $98 173 173 Balance at December 31, 1997 4,309 116,027 238,955 (8) $38,263 Net income 16,162 16,162 Cash dividends (15,900) Foreign currency translation adjustment, net of income taxes of $53 93 93 Balance at December 31, 1998 4,309 116,027 239,217 85 $16,255 Net income 45,866 45,866 Cash dividends (16,600) Dividend of shares of Questar Energy Services 1,905 Unrealized loss on securities available for sale, net of income tax credit of $1,557 (2,515) (2,515) Foreign currency translation adjustment, net of income taxes of $284 (460) (460) Balance at December 31, 1999 4,309 116,027 270,388 (2,890) $42,891 Net income (unaudited) 15,049 15,049 Cash dividends (4,325) Unrealized gain on securities available for sale, net of income taxes of $811 1,309 1,309 Foreign currency translation adjustment net of income taxes of $263 (312) (312) Balance at March 31, 2000 (unaudited) $4,309 $116,027 $281,112 ($1,893) $16,046
See accompanying notes to consolidated financial statements. -37- QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
For the Three Months For the Year Ended March 31, Ended December 31, 2000 1999 1999 1998 1997 (Unaudited) OPERATING ACTIVITIES Net income $15,049 $ 8,253 $ 45,866 $16,162 $38,090 Depreciation and amortization 21,148 20,194 81,150 71,951 67,667 Deferred income taxes 357 (226) 9,381 (4,619) (2,428) Write-down of full cost oil and gas properties 31,000 6,000 Write-down of gas gathering properties 3,000 (Income) loss from unconsolidated affiliates, net of cash distributions (924) 85 (66) 1,211 1,872 Gain from sale of securities (388) Changes in operating assets and liabilities Accounts receivable (3,734) 9,697 (2,631) 20,572 22,196 Inventories 6,133 7,288 (468) (4,996) (1,045) Prepaid expenses and deposits (1,354) 547 (83) 555 (191) Accounts payable and accrued expenses (4,651) (13,323) 5,655 (7,002) (3,883) Federal income taxes payable 2,036 2,385 127 2,399 3,620 Other assets (1,305) 95 (783) (628) 1,213 Other liabilities (1,623) 1,976 3,097 908 824 NET CASH PROVIDED FROM OPERATING ACTIVITIES 31,132 36,971 140,857 127,513 136,935 INVESTING ACTIVITIES Capital expenditures Purchases of property, plant and equipment (80,336) (13,301) (109,405) (252,671) (92,310) Other investments (812) (24,864) (1,875) (80,336) (14,113) (134,269) (254,546) (92,310) Proceeds from disposition of property, plant and equipment 309 1,324 38,624 7,857 11,018 Proceeds from sale of securities 1,214 NET CASH USED IN INVESTING ACTIVITIES (80,027) (12,789) (94,426) (246,689) (81,292) FINANCING ACTIVITIES Change in notes receivable from Questar 4,000 (10,600) 21,100 8,400 (17,200) Change in notes payable to Questar 25,200 (10,400) (97,300) 77,500 (23,700) Change in short-term debt (10,000) Cash in escrow balance (583) (36,727) Checks written in excess of cash balances (1,246) 1,246 (2,505) Issuance of long-term debt 33,402 3,640 275,000 64,343 63,547 Payment of long-term debt (5,000) (195,000) (14,283) (48,432) Payment of dividends (4,325) (4,150) (16,600) (15,900) (16,325) NET CASH PROVIDED FROM (USED IN FINANCING ACTIVITIES 51,448 (21,510) (48,281) 120,060 (54,615) Foreign currency translation adjustment (347) (44) (4) (14) CHANGE IN CASH AND CASH EQUIVALENTS 2,206 2,672 (1,894) 880 1,014 Beginning cash and cash equivalents 1,894 1,894 1,014 ENDING CASH AND CASH EQUIVALENTS $2,206 $4,566 $ - $1,894 $1,014
See accompanying notes to consolidated financial statements. -38- QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1 - Summary of Accounting Policies Principles of Consolidation: The consolidated financial statements contain the accounts of Questar Market Resources, Inc. and subsidiaries (the "Company" or "QMR"). The Company is a wholly-owned subsidiary of Questar Corporation ("Questar"). QMR, through its subsidiaries, conducts gas and oil exploration, development and production, gas gathering and processing, and wholesale energy marketing. Questar Exploration and Production Company ("Questar E&P"), formerly named Celsius Energy Company and Universal Resources Corporation, conducts the exploration, development and production activities. Wexpro Company ("Wexpro") operates and develops producing properties on behalf of an affiliate, Questar Gas Company ("Questar Gas"). Questar Gas Management Company ("Questar Gas Management") conducts gas gathering and plant processing activities. Questar Energy Trading Company ("Questar Energy Trading") performs wholesale energy marketing activities and, through a 75% interest in Clear Creek Storage Company, LLC, constructed and operates a gas storage facility. All significant intercompany balances and transactions have been eliminated in consolidation. Investments in Unconsolidated Affiliates: The Company owns a 15% interest in Canyon Creek Compression Co., and a 50% interest in Blacks Fork Gas Processing Co. The Company uses the equity method to account for investments in affiliates in which it does not have control and generally, its investment in these affiliates equals the underlying equity in net assets. Interim Financial Data: The unaudited consolidated financial statements as of March 31, 2000, and for the three-month periods ended March 31, 2000 and 1999, and all related footnote information for these periods have been prepared on the same basis as the audited financial statements and, in the opinion of management, include all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States and pursuant to the rules and regulations of the Securities and Exchange Commission. 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 amounts of assets and liabilities and disclosure of contingent liabilities reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Revenue Recognition: Revenues are recognized in the period that services are provided or products are delivered. The Company uses the sales method of accounting for its gas revenues whereby the Company recognizes sales revenue on all gas sold to its purchasers. A liability is recognized to the extent that the Company has an imbalance in excess of its share of remaining reserves in an underlying property. The Company's net gas imbalance at December 31, 1999, 1998, and 1997 were not significant. Wexpro settlement agreement-oil income sharing: Wexpro settlement agreement-oil income sharing represents payments made to Questar Gas for their share of the income from oil and NGL products associated with cost of service oil properties pursuant to the terms of the Wexpro settlement agreement (Note 10). Cash and Cash Equivalents: Cash equivalents consist principally of repurchase agreements with original maturities of three months or less. Notes receivable from Questar: Notes receivable from Questar represent interest bearing demand notes for excess cash balances loaned to Questar until needed in the Company's operations. The funds are centrally managed by Questar and earn an interest rate that is identical to the interest rate paid by the Company for borrowings from Questar. Property, Plant and Equipment: QMR uses the full cost accounting method for the majority of its oil and gas exploration and development activities. However, as ordered by the Utah Public Service Commission, the successful efforts method of accounting is utilized -39- with respect to costs associated with certain "cost of service" oil and gas properties managed and developed by Wexpro and regulated for ratemaking purposes. Cost of service oil and gas properties are those properties for which the operations and return on investment are regulated by the Wexpro settlement agreement (see Note 10). Pursuant to the settlement agreement, production from the gas properties operated by Wexpro is delivered to Questar Gas at Wexpro's cost of providing this service. That cost includes a return on Wexpro's investment. While oil produced from the cost of service properties is sold at market prices, the proceeds are credited pursuant to the terms of the settlement agreement allowing Questar Gas to share in the proceeds for the purpose of reducing natural gas rates. Full Cost Accounting - Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas reserves, including certain directly related internal employee costs, are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, and costs related to such activities. Internal costs capitalized are directly attributable to acquisition, exploration, and development activities and do not include costs related to production, general corporate overhead or similar activities. Exclusive of field-level costs, the Company capitalized $3,003,000, $2,603,000, and $1,590,000 of internal costs in 1999, 1998, and 1997, respectively. Costs associated with production and general corporate activities are expensed in the period incurred, as are interest costs. Sales of oil and gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The Company limits, on a country by country cost center basis, the capitalized costs of oil and gas properties, net of accumulated amortization and related deferred taxes, to the present value of estimated future net revenues from proved oil and gas reserves, based upon current economic and operating conditions and estimated future development expenditures, discounted at 10%, plus the cost of unproved properties not being amortized, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is expensed. The Company recorded write-downs of oil and gas properties pursuant to the ceiling limitation required by the full cost accounting method amounting to $31 million in 1998 and $6 million in 1997. Capitalized costs are amortized, on a country by country cost center basis, by an equivalent unit of production method based upon production and estimates of proved reserves quantities. The Company presently has two cost centers: the United States and Canada. Amortizable costs include developmental drilling in progress as well as estimates of future development costs of proved reserves, but exclude the costs of certain unproved oil and gas properties until the properties are evaluated. The estimated costs of future site restoration, dismantlement, and abandonment of producing properties are expected to be offset by the estimated salvage value of the lease and well equipment. The aggregate costs of unproved properties not being amortized are assessed at least annually for possible impairments or reduction in value. Significant properties are assessed individually. If a reduction in value has occurred, costs being amortized are increased. Of the $69.8 million of net unproved property costs at December 31, 1999 excluded from the amortizable base, $14.2 million, $27.7 million, and $7.8 million were incurred in 1999, 1998, and 1997, respectively. Based on anticipated future exploration and development activities, the Company expects the majority of the costs of unproved properties currently excluded to be evaluated and included in the amortization calculation within the next five years. Successful Efforts Accounting - The Company uses the successful efforts method of accounting with respect to costs associated with the development of cost of service oil and gas properties. The cost to drill and equip -40- development wells, successful or unsuccessful, and construct appurtenant facilities are capitalized. Geological and geophysical costs are expensed as incurred. Capitalized costs are amortized on an individual field basis using the unit-of-production method based upon proved oil and gas reserves attributable to the field. Costs of future site restoration, dismantlement, and abandonment for producing properties are accrued as part of depreciation and amortization expense for tangible equipment by assuming no salvage value in the calculation of the unit of production rate. Gathering, Processing and Marketing - The investments in gathering facilities, processing plants and other general support property, plant and equipment are generally depreciated using the straight-line method based upon estimated useful lives ranging from 3 to 20 years. SFAS No. 121 - The Company follows the provisions of Statement of Financial Accounting Standards (SFAS) 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" in evaluating impairment of the Company's cost of service oil and gas properties (accounted for under the successful efforts method) and its gathering, processing and other property, plant and equipment. The Company recorded a write-down of its investment in gas gathering properties of $3 million in 1997 under the provisions of SFAS 121. Depreciation and amortization - Depreciation and amortization expense consists of the following components (in thousands, except for rates):
Full cost oil and gas properties $16,076 $15,401 $61,057 $55,015 $51,175 Amortization rate, per unit of production (Mcfe) U.S. .80 .85 .81 .83 .81 Canada .81 .60 .65 1.04 1.17 Cost of service oil and gas properties 3,537 3,024 12,665 11,379 10,213 Amortization rate, per unit of production (Mcfe) .43 .40 .42 .39 .39 Gathering, processing and marketing 1,364 1,180 4,886 4,983 5,690 Total $20,977 $19,605 $78,608 $71,377 $67,078
-41- Capitalized Interest and Allowance for Funds Used During Construction: The Company capitalizes interest costs, when applicable, related to gathering, processing, and marketing activities during the construction period of plant and equipment. Interest costs related to full cost oil and gas activities are expensed in the period incurred. Gross debt expense aggregated $17,363,000, $13,249,000, and $10,882,000 in 1999, 1998, and 1997, respectively. Debt expense was reduced by $618,000 of capitalized interest in 1998. Under provisions of the Wexpro settlement agreement, the Company capitalizes an allowance for funds used during construction ("AFUDC") on cost of service construction projects. AFUDC amounted to $357,000, $745,000, and $604,000 in 199, 1998, and 1997, respectively, and is included in Interest and Other Income in the Consolidated Statements of Income. Foreign Currency Translation: The Company conducts gas and oil exploration and production activities in western Canada. The local currency is the functional currency of the Company's foreign operations. Translation from the functional currency to U. S. dollars is performed for balance sheet accounts using the exchange rate in effect at the balance-sheet date. Revenue and expense accounts are translated using an average exchange rate for the period. Adjustments resulting from such translations are reported as a separate component of other comprehensive income in shareholder's equity. Deferred income taxes have been provided on translation adjustments because the earnings are not considered to be permanently invested. Market Risks: The Company's primary market-risk exposures arise from commodity price changes for natural gas and oil, changes in long-term interest rates, and foreign currency exchange rates. Hedging Policy - The Company has established policies and procedures for managing market risks throught he use of commodity-based derivative arrangements. A primary objective of these hedging transactions is to protect the Company's product sales from adverse changes in energy prices. The volume of production hedged and the mix of derivative instruments employed are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by the Board of Directors. Additionally, under the terms of the Company's revolving credit facility, not more than 75% of the Company's production quantities can be committed to hedging arrangements. The Company does not enter into derivative arrangements for speculative purposes. Energy Price Risk- QMR enters into swaps, futures contracts or option agreements to hedge exposure to price fluctuations in connection with marketing of the Company's natural gas and oil production, and to secure a known margin for the purchase and resale of gas, oil and electricity in marketing activities. It is expected there is a high degree of correlation between changes in the market value of such contracts and the market price ultimately received on the hedged physical transactions. In these Consolidated Financial Statements, cash flows from the hedge contracts are reported in the same category as cash flows from the hedged assets. Contracts no longer qualifying for high correlation with the physical transactions would be market-to-market and recognized in current period income. Interest Rate Risk- The Company uses variable rate debt as part of its financing plans. These agreements expose the Company to market risk related to changes in interest rates. -42- Credit Risk- The Company's primary operating areas are the Rocky Mountain region of the United States and Canada and the Mid-continent region of the United States. Exposure to credit risk may be impacted by the concentration of customers in these regions due to changes in economic or other conditions. Customers include numerous entities that may be affected differently by changing conditions. Management believes that its credit-review procedures, loss reserves and customer deposits have adequately provided for usual and customary credit-related losses. Commodity-based hedging arrangements also expose the Company to credit risk. The Company monitors the creditworthiness of its counterparties, which generally are major financial institutions, and believes that losses from non-performance are unlikely to occur. Income Taxes: The Company accounts for income tax expense on a separate return basis. Pursuant to the Internal Revenue Code and associated Regulations, the Company's operations are consolidated with those of Questar and its subsidiaries for income tax purposes. The Company records tax benefits as they are generated. The Company receives payments from Questar for such tax benefits as they are utilized on the consolidated return. Comprehensive Income: QMR reports comprehensive income on the Consolidated Statements of Shareholder's Equity. Other comprehensive income transactions that currently apply to QMR result from changes in market value of securities available for sale and changes in holding value resulting from foreign currency translation adjustments. These transactions are not the culmination of the earnings process, but result from periodically adjusting historical balances to market value. The balances in accumulated foreign currency translation adjustments and unrealized losses on securities available for sale amounted to $375,000 and $2,515,000, respectively, at December 31, 1999. The balance in accumulated foreign currency translation adjustments at December 31, 1998, was $85,000. Income is realized when the securities available for sale are sold. Income taxes associated with realized gains from selling securities available for sale were $146,000 in 1999. New accounting standard: The Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" in June 1998. The Statement establishes accounting and reporting standards requiring that the fair value of all derivative instruments be recorded in the balance sheet as either an asset or liability. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met wherein gains and losses are to be reflected in other comprehensive income in shareholder's equity until the hedged item is recognized. Due to the issuance of SFAS No. 137, which deferred the effective date of SFAS No. 133, the Company is required to adopt the statement for fiscal years beginning after June 15, 2000. The Company has not quantified the impact of adopting SFAS No. 133, but plans on adopting the statement by January 1, 2001. During 2000, the FASB issued SFAS No. 138, which amends the accounting and reporting standards of SFAS No. 133 for certain derivative instruments and certain hedging activities and should be adopted concurrently with SFAS No. 133, according to its provisions and the issuance of SFAS No. 137. The Company has not quantified the impact SFAS No. 138 will have upon the adoption of SFAS No. 133. Reclassifications: Certain reclassifications were made to the 1998 and 1997 financial statements to conform with the 1999 presentations. Note 2 - Acquisitions HSRTW, Inc. A subsidiary of QMR acquired 100% of the common stock of HSRTW, Inc., a wholly owned subsidiary of HS Resources, Inc. for $155 million, effective September 1, 1998. QMR obtained an estimated 150 Bcfe of -43- proved oil and gas reserves primarily in Oklahoma, Texas, Arkansas, and Louisiana as a result of the transaction. The cash transaction was accounted for under the purchase method of accounting for business combinations. The Company's consolidated statement of income for the year ended December 31, 1998, includes only four months of operations from the HSRTW acquisition. The following unaudited pro forma consolidated results of operations assume the acquisition occurred on January 1 of each year. The pro forma results do not necessarily represent results which would have occurred if the acquisition had taken place on the basis assumed above, nor are they indicative of the results of future combined operations. For the year ended December 31, (In Thousands) 1998 1997 (Unaudited) Total Revenuese $479,649 $573,959 Net Income $ 21,215 $ 45,846 The pro forma amounts reflect the combined results of the Company, HSRTW, and the following purchase accounting adjustments for the periods presented: depreciation and amortization calculated on the basis of the allocated purchase price and acquired proved reserves; incremental interest expense on additional debt that would have been incurred to finance the acquisition; estimated general and administrative expenses based on consolidated efficiencies; and estimated income tax effects on the pro forma adjustments. Canor Energy Ltd. On January 26, 2000, a subsidiary of QMR acquired 100% of the outstanding shares of Canor from NI Canada ULC, a subsidiary of Northwest Natural Gas Co., for cash of $US 61 million plus the assumption of $5.4 million of short-term debt. The transaction was accounted for as a purchase. Canor owns and/or operates more than 800 wells located in Alberta, British Columbia, and Saskatchewan provinces of Canada. Canor's proven gas and oil reserves were estimated at 61.1 Bcfe. Assets purchased and liabilities assumed were as follows: (In Thousands) Cash $ 245 Other current assets 3,502 Property, plant and equipment 73,720 Other assets 282 Short-term debt (5,444) Other current liabilities (4,356) Deferred income taxes (4,976) Other liabilities (1,989) Total purchase price, including acquisition costs $60,984 The Company's consolidated statement of income for the three months ended March 31, 2000 (unaudited) includes the results of operations of Canor from the date of acquisition. Pro forma results of operations for the three months ended March 31, 2000 and 1999 are not materially different from that presented in the accompanying Consolidated Statements of Income. -44- Note 3 - Other Assets Other assets include the following:
As of March 31, As of December 31, 2000 1999 1998 (In Thousands) (Unaudited) Cash held in escrow account (a) $37,310 $36,727 Securities available for sale (b) 12,522 10,402 Other 2,542 952 $628 Total other assets $52,374 $48,081 $628 _______________
(a)Proceeds from the sale of nonstrategic oil and gas properties in November and December of 1999, were placed in escrow with a qualified intermediary in accordance with the statutory requirements for a tax-free exchange under U.S. Internal Revenue Code Section 1031. (b)Securities available for sale are recorded at their fair value on the balance sheet, based on published share prices. Using the average cost method, the cost basis of the common stock held was $14.5 million at both March 31, 2000 and December 31, 1999, with unrealized holding losses of $2.0 million on each respective date. Changes in net unrealized holding gain or loss on available for sale securities that have been included as a separate component of shareholder's equity were $1.3 million after tax gain for the three months ended March 31, 2000 and a $2.5 million loss for the twelve months ended December 31, 1999. Proceeds from sales of available-for-sale securities were $1.2 million in 1999, which resulted in gross realized gains of $0.4 million. Note 4 - Debt QMR has a $300 million senior revolving credit facility agented by Bank of America. Borrowing under this agreement amounted to $264.9 million at December 31, 1999 at a 6.54% interest rate. The agreement was entered into April 1999 and replaced an unsecured short-term and long-term line-of-credit arrangements with various banks. The loan is segmented into US and Canadian portions. The US portion of the loan is a 5-year facility with $227 million available. The Canadian portion amounts to $68 million and is a 6-year facility. The interest rate is generally equal to LIBOR plus a small premium. Under the most restrictive terms of the senior-revolving credit facility, QMR could have paid a dividend of $57.6 million at December 31, 1999. Maturities of long-term debt for the five years following December 31, 1999, are as follows: (In Thousands) 2000 $ - 2001 2,995 2002 30,995 2003 2,995 2004 179,995 -45- Questar makes loans to QMR under a short-term borrowing arrangement. Short-term notes payable to Questar outstanding as of December 31, 1999 amounted to $24.5 million with an average interest rate of 6.61% and $121.8 million as of December 31, 1998 with an interest rate of 5.71%. Cash paid for interest was $16,964,000 in 1999, $13,229,000 in 1998 and $11,557,000 in 1997. Note 5 - Financial Instruments The carrying amounts and estimated fair values of the Company's financial instruments were as follows:
December 31, 1999 December 31, 1998 Carrying Estimated Fair Carrying Estimated Value Value Value Fair Value (In Thousands) Financial assets Cash and cash equivalents $1,894 $1,894 Notes receivable from Questar $4,000 $4,000 25,100 25,100 Financial liabilities Short-term loans 25,746 25,746 121,800 121,800 Long-term debt 264,894 264,894 181,624 181,624 Gas and oil price hedging contracts (6,200) 6,000
The Company used the following methods and assumptions in estimating fair values: (1) Cash and cash equivalents, notes receivable from Questar and short-term loans - the carrying amount approximates fair value; (2) Long-term debt - the carrying amount of variable-rate debt approximates fair value; (3) Gas and oil price hedging contracts - the fair value of contracts is based on market prices as posted on the NYMEX from the last trading day of the year. The average price of the oil price hedging contracts at December 31, 1999 was $18.83 per bbl and was based on the average of fixed amounts in contracts which settle against the NYMEX. All oil price hedging contracts relate to Company-owned production where basis adjustments would result in a net to the well price of between $17.22 and $17.67 per bbl. The average price of the gas price hedging contracts at December 31, 1999 was $2.22 per Mcf representing the average of contracts with different terms including fixed, various into-the-pipe postings and NYMEX references. Gas price hedging contracts were in place for QMR-owned production and gas marketing transactions. Transportation and heat value adjustments on the hedges of Company-owned gas as of December 31, 1999 would result in an average price of between $2.15 and $2.23 per Mcf, net back to the well. Fair value is calculated at a point in time and does not represent the amount the Company would pay to retire the debt securities. In the case of gas-and-oil price-hedging activities, the fair value calculation does not consider changes in the fair value of the corresponding scheduled physical transactions (i.e., the correlation between the index price and the price to be realized for the physical delivery of oil or gas production). Energy Price Risk Management: The Company held open hedge contracts covering the price exposure for about 72.1 million Dth of gas and 2.4 million barrels of oil at December 31, 1999 and 45.3 million Dth of gas and 464,000 barrels of oil at December 31, 1998. The hedging contracts are primarily for gas and oil marketing activities, but also include QMR-owned production. The contracts at December 31, 1999 had terms extending through December 2001 with about 65% of those contracts expiring by the end of 2000. A primary objective of energy-price hedging is to protect product sales from adverse changes in energy prices. The Company does not enter into hedging contracts for speculative purposes. -46- Credit Risk Management: The Company's primary operating areas are the Rocky Mountain and Mid-Continent regions of the United States. Exposure to credit risk may be impacted by the concentration of customers in these regions due to changes in economic or other conditions. Customers include numerous industries that may be affected differently by changing conditions. Management believes that its credit review procedures, loss reserves, and collection procedures have adequately protected against unusual credit related losses. Commodity-based hedging arrangements also expose the Company to credit risk. The Company monitors the creditworthiness of its counterparties, which generally are major financial institutions, and believes that losses from non- performance are unlikely to occur. Interest Rate Risk Management: The Company had $264.9 million of variable rate long-term debt outstanding at December 31, 1999. The book value of variable-rate debt approximates fair value. Foreign Currency Risk Management: The Company does not hedge the foreign currency exposure of its foreign operation's net assets and long-term debt. The net assets of the foreign operation were negative at December 31, 1999. Long-term debt owned by the foreign operation, amounting to $59.9 million (U.S.), is expected to be repaid from the future foreign operations. Securities Available for Sale: Securities available for sale represent equity instruments traded on national exchanges. The value of these investments is subject to day to day market volatility. Note 6 - Income Taxes The components of income taxes expense (benefit) for years ended December 31 were as follows:
1999 1998 1997 (In Thousands) Federal Current $11,411 $4,263 $14,574 Deferred 4,826 (86) (1,218) State Current 1,568 228 1,350 Deferred 620 1,007 (291) Foreign 159 (6,431) (4,005) Income taxes $18,584 ($1,019) $10,410
The difference between income tax expense and the tax computed by applying the statutory federal income tax rate of 35% to income from continuing operations before income taxes is explained as follows:
1999 1998 1997 (In Thousands) Income from continuing operations before income taxes $64,450 $15,706 $49,521 Federal income taxes at statutory rate $22,558 $ 5,497 $17,332 State income taxes, net of federal income tax benefit 1,422 803 745 Nonconventional fuel credits (5,282) (5,736) (6,633) Foreign income taxes 48 (1,771) (630) Other (162) 188 (404) Income taxes $18,584 ($1,019) $10,410 Effective income tax rate 28.8% - 21.0%
-47- Significant components of the Company's deferred tax liabilities and assets at December 31 were as follows:
1999 1998 (In Thousands) Deferred tax liabilities Property, plant and equipment $74,333 $64,674 Other 509 205 74,842 64,879 Deferred tax assets Alternative minimum tax and nonconventional fuel credit carry-forwards 2,468 6,535 Reserves, compensation plans and other 12,438 6,231 14,906 12,766 Net deferred tax liabilities $59,936 $52,113
The Company paid $7,183,000 in 1999 and $9,029,000 in 1997 for income taxes. Cash received for income taxes amounted to $1,856,000 in 1998. Note 7 - Litigation and Commitments At December 31, 1999, Questar E&P, as well as QMR and Questar, were among the named defendants in a class action lawsuit involving royalty payments in Oklahoma state court. In Bridenstine vs. Kaiser-Francis Oil Company, the plaintiffs alleged various fraud and contract claims against all defendants for a 17-year period. While this litigation did not specify the amount of damages being claimed, estimates at times were in excess of $80 million, plus punitivie damages. The plaintiff's primary claim alleged that a transportation fee charged against royalty payments was improper or excessive. The claims involved wells connected to an intrastate pipeline system that Questar Gas Management presently owns and operates. Kaiser-Francis and Questar E&P are the major working interest owners and operators of a majority of wells connected to this pipeline system. Questar E&P disputed plaintiff's claims. On January 4, 2001, a district court judge in Texas County, Oklahoma, approved the settlement agreement reached by the Company and Union Pacific Resources Company (predecessor in interest to Questar E&P), as defendants in the Bridenstine case. Under the terms of the settlement, the Company and Union Pacific Resources paid a total of $22.5 million ($16.5 million by the Company) to resolve all of the issues in the litigation. Questar E&P has paid the settlement funds, which are being held in escrow pending the expiration of a 30-day appeal period following the entry of the judge's order. Payment of the settlement funds did not have a material adverse effect on the Company's results of operations, financial position, or liquidity. The Company regularly reviews potential liabilities related to legal proceedings and records appropriate accruals after considering estimates of the outcome of such matters and our experience in contesting, litigating, and settling similar matters. While it is not currently possible to predict or determine the outcome of the various legal proceedings against QMR, it is the opinion of management that the outcomes will not have a material adverse effect on the Company's future results of operations, financial position or liquidity. Questar Energy Trading has contracted for firm-transportation services with various pipelines to transport 76.2 MDths per day of gas. The contracts extend for the next seven years and have an annual cost of approximately $3 million. Due to market conditions and competition, it is possible that Questar Energy Trading may be unable to sell enough gas to fully utilize the contracted capacity. Also, Questar Energy Trading has reserved firm-storage capacity of 1,065 MDths per day with Questar Pipeline through 2008 with an annual cost of $627,000. -48- The minimum future payments under the terms of long-term operating leases for the Company's primary office locations for the five years following December 31, 1999, are as follows: (In Thousands) 2000 $1,980 2001 1,918 2002 1,371 2003 507 2004 43 Total minimum future rental payments have not been reduced for sublease rental receipts of $96,000, $96,000, and $24,000, which are expected to be received in the years ended December 31, 2000, 2001, and 2002, respectively. Total rental expense amounted to $1,804,000, $1,397,000, and $1,112,000 in 1999, 1998, and 1997, respectively. Sublease rental receipts were $94,000 in 1999. Note 8 - Employment Benefits Pension Plan: Substantially all of QMR's employees are covered by Questar's defined benefit pension plan. Benefits are generally based on years of service and the employee's 72-pay period interval of highest earnings during the ten years preceding retirement. It is the Company's policy to make contributions to the plan at least sufficient to meet the minimum funding requirements of applicable laws and regulations. Plan assets consist principally of equity securities and corporate and U.S. government debt obligations. Pension cost was $887,000 in 1999, $761,000 in 1998 and $1,345,000 in 1997. Included in pension cost for 1997 is $419,000 of expense associated with an early retirement package offered to a limited number of the Company's employees. QMR's portion of plan assets and benefit obligations is not determinable because the plan assets are not segregated or restricted to meet the Company's pension obligations. If the Company were to withdraw from the pension plan, the pension obligation for the Company's employees would be retained by the pension plan. At December 31, 1999, Questar's fair value of plan assets exceeded the accumulated benefit obligation. Postretirement Benefits Other Than Pensions: QMR pays a portion of health-care costs and life insurance costs for employees. The Company linked the health-care benefits to years of service and limited the Company's monthly health care contribution per individual to 170% of the 1992 contribution. Employees hired after December 31, 1996, do not qualify for postretirement medical benefits under this plan. The Company's policy is to fund amounts allowable for tax deduction under the Internal Revenue Code. Plan assets consist of equity securities, and corporate and U.S. government debt obligations. The Company is amortizing the transition obligation over a 20-year period, which began in 1992. Costs of postretirement benefits other than pensions were $1,158,000 in 1999 and $1,018,000 in 1998 and $1,083,000 in 1997. QMR's portion of plan assets and benefit obligations related to postretirement medical and life insurance benefits is not determinable because the plan assets are not segregated or restricted to meet the Company's obligations. Postemployment Benefits: The Company recognizes the net present value of the liability for postemployment benefits, such as long-term disability benefits and health-care and life-insurance costs, when employees become eligible for such benefits. Postemployment benefits are paid to former employees after employment has been terminated but before retirement benefits are paid. The Company accrues both current and future costs. The liability is remeasured each year and the change is recorded in income. Postemployment benefits accumulate for salary continuation, health-care and life-insurance costs. Benefits are paid from the Company's general funds. The Company's postemployment benefit liability at December 31, 1999 was $381,000 and in 1998 was $376,000 based on discount rates of 7.75% and 6.75%, respectively. -49- Employee Investment Plan: The Company participates in Questar's Employee Investment Plan (EIP), which allows eligible employees to purchase Questar common stock or other investments through payroll deduction of pretax earnings. The Company makes matching contributions to the EIP of 80% of the first 6% of salary contributed by employees and contributes an additional $200 of common stock in the name of each eligible employee. The Company's expense and contribution to the plan was $895,000 in 1999, $811,000 in 1998 and $747,000 in 1997. Note 9 - Related Party Transactions QMR receives a significant portion of its revenues from services provided to Questar Gas. The Company received $79,324,000 in 1999, $75,171,000 in 1998 and $72,138,000 in 1997 for operating cost of service oil and gas properties, gathering gas and supplying a portion of gas for resale, among other services provided to Questar Gas. Operation of cost of service oil and gas properties is described in Wexpro Settlement Agreement (Note 10). The Company also received revenues from other affiliated companies totaling $384,000 in 1999, $310,000 in 1998 and $269,000 in 1997. Questar performs certain administrative functions for QMR. The Company was charged for its allocated portion of these services which totaled $4,469,000 in 1999, $3,970,000 in 1998 and $5,311,000 in 1997. These costs are included in operating and maintenance expenses and are allocated based on each affiliate's proportional share of revenues; net of product costs; property, plant and equipment; and payroll. Management believes that the allocation method is reasonable and that expenses would be substantially the same if incurred on a standalone basis. QMR's subsidiaries contracted for transportation and storage services with Questar Pipeline and paid $3,378,000 in 1999, $3,968,000 in 1998 and $4,011,000 in 1997 for those services. Questar InfoComm Inc is an affiliated company that provides some data processing and communication services to QMR. The Company paid Questar InfoComm $2,276,000 in 1999, $2,273,000 in 1998 and $2,391,000 in 1997. QMR has a 5-year lease with Questar for space in an office building located in Salt Lake City, Utah, and owned by a third party. The annual lease payment, which began October of 1997, is $863,000. The Company received interest income from affiliated companies of $681,000 in 1999, $1,908,000 in 1998 and $2,370,000 in 1997. QMR incurred debt expense to affiliated companies of $3,350,000 in 1999, $3,331,000 in 1998 and $2,661,000 in 1997. Note 10 - Wexpro Settlement Agreement Wexpro's operations are subject to the terms of the Wexpro settlement agreement. The agreement was effective August 1, 1981, and sets forth the rights of Questar Gas' utility operations to share in the results of Wexpro's operations. The agreement was approved by the PSCU and PSCW in 1981 and affirmed by the Supreme Court of Utah in 1983. Major provisions of the settlement agreement are as follows: a. Wexpro continues to hold and operate all oil-producing properties (productive oil reservoirs) previously transferred from Questar Gas' nonutility accounts. The oil production from these properties is sold at market prices, with the revenues used to recover operating expenses and to give Wexpro a return on its investment. The after tax rate of return is adjusted annually and is approximately 13.7%. Any net income remaining after recovery of expenses and Wexpro's return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%. b. Wexpro conducts developmental oil drilling on productive oil reservoirs and bears any costs of dry holes. Oil discovered from these properties is sold at market prices, with the revenues used to recover operating expenses and to give Wexpro a return on its investment in successful wells. The after tax rate of return is adjusted annually and is approximately 18.7%. Any net income remaining after recovery of expenses and Wexpro's return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%. -50- c. Amounts received by Questar Gas from the sharing of Wexpro's oil income are used to reduce natural-gas costs to utility customers. d. Wexpro conducts developmental gas drilling on productive gas reservoirs and bears any costs of dry holes. Natural gas produced from successful drilling is owned by Questar Gas. Wexpro is reimbursed for the costs of producing the gas plus a return on its investment in successful wells. The after tax rate of return allowed Wexpro is approximately 21.7%. e. Wexpro operates productive gas reservoir properties owned by Questar Gas. Wexpro is reimbursed for its costs of operating these properties, including a rate of return on any investment it makes. This after tax rate of return is approximately 13.7%. Note 11 - Discontinued Operations - Transfer of Questar Energy Services QMR transferred all of its investment in Questar Energy Services, Inc. ("Questar Energy Services"), a wholly-owned subsidiary to Questar Regulated Services Company ("Questar Regulated Services"), an affiliate, effective January 1, 1999. Questar Regulated Services, a wholly-owned subsidiary of Questar, is a sub-holding company that holds the investment of Questar Gas, a retail natural gas distributor. The transfer was in the form of a dividend of 100% of the shares of Questar Energy Services at book value. No gain or loss was generated as a result of the transfer. Questar Energy Services provides energy management equipment, installation, and service contracts for commercial and industrial clients and home security systems, service contracts, and equipment financing to residential customers and markets its services and products to many of the same customers served by Questar Gas. Summarized information relating to discontinued operations are as follows: For the Year Ended December 31, 1998 1997 (In thousands) Revenues $2,355 $595 Operating (loss) (1,180) (1,773) Net (loss) (563) (1,021) At December 31, 1998 1997 (In thousands) Total assets $7,230 $4,326 Total liabilities 9,135 5,668 Common equity (deficit) (1,905) (1,342) Note 12 - Business Segment Information QMR is a sub-holding company that has three primary business segments: exploration and production; the management and development of cost of service properties; and gathering, processing and marketing. QMR's reportable segments are strategic business units with similar -51- operations and management objectives. The reportable segments are managed separately because each segment requires different operational assets, technology, and management strategies. Operating Segment Information
For the Three Months For the Year Ended March 31, Ended December 31, 2000 1999 1999 1998 1997 (Unaudited) (In Thousands) Revenues from Unaffiliated Customers Exploration and production $49,509 $36,200 $162,475 $135,509 $135,060 Cost of service 3,844 2,124 8,844 10,025 14,474 Gathering, processing, and marketing 66,118 56,319 247,284 237,257 301,699 $119,471 $94,643 $418,603 $382,791 $451,233 Revenues from Affiliated Companies Cost of service $17,130 $15,094 $62,335 $58,581 $50,020 Gathering, processing, and marketing 5,160 6,109 17,373 16,900 22,387 $22,290 $21,203 $79,708 $75,481 $72,407 Depreciation and Amortization Expense Exploration and production $16,076 $15,401 $61,057 $55,015 $51,175 Cost of service 3,537 3,024 12,665 11,379 10,213 Gathering, processing, and marketing 1,364 1,180 4,886 4,983 5,690 $20,977 $19,605 $78,608 $71,377 $67,078 Operating Income (Loss) Exploration and production (1) $15,805 $4,975 $37,406 ($6,063) $27,555 Cost of service 9,031 7,794 32,948 28,218 24,988 Gathering, processing, and marketing (2) 839 1,574 6,424 3,474 2,294 $25,675 $14,343 $76,778 $25,629 $54,837 Interest and Other Income Exploration and production $806 $564 $2,209 $2,256 $4,159 Cost of service 118 251 534 971 1,651 Gathering, processing and marketing 169 32 1,529 411 44 $1,093 $847 $4,272 $3,638 $5,854 Debt expense Exploration and production $4,626 $3,834 $14,770 $11,552 $8,354 Cost of service 123 116 582 149 340 Gathering, processing and marketing 621 313 2,011 930 2,188 $5,370 $4,263 $17,363 $12,631 $10,882 -52-
For the Three Months For the Year Ended March 31, Ended December 31, 2000 1999 1999 1998 1997 Income Tax Expense (Credit) Exploration and production $3,589 ($667) $4,037 ($12,102) $1,079 Cost of service 3,239 2,845 12,020 10,387 9,316 Gathering, processing and marketing 520 465 2,527 696 15 $7,348 $2,643 $18,584 ($1,019) $10,410 Income (Loss) from Continuing Operations Exploration and production $8,396 $2,372 $20,808 ($3,257) $22,281 Cost of service 5,787 5,084 20,880 18,653 16,983 Gathering, processing, and marketing 866 797 4,178 1,329 (153) $15,049 $8,253 $45,866 $16,725 $39,111 Fixed Assets - Net Exploration and production $549,552 $492,815 $482,043 $496,884 $373,070 Cost of service 134,968 128,328 137,584 129,573 113,228 Gathering, processing, and marketing 71,024 66,896 71,354 69,055 68,878 $755,544 $688,039 $690,981 $695,512 $555,176 Capital Expenditures Exploration and production $78,011 $10,994 $81,863 $219,608 $50,470 Cost of service 1,367 1,858 21,076 26,653 26,837 Gathering, processing and marketing 958 1,261 31,330 8,285 15,003 $80,336 $14,113 $134,269 $254,546 $92,310
Geographic Information
For the Three Months For the Year Ended March 31, Ended December 31, 2000 1999 1999 1998 1997 (In Thousands) (Unaudited) Revenues United States $134,788 $113,362 $485,995 $447,798 $514,827 Canada 6,973 2,484 12,316 10,474 8,813 $141,761 $115,846 $498,311 $458,272 $523,640 Fixed Assets-Net United States $648,922 $653,791 $654,961 $662,260 $511,547 Canada 106,622 34,248 36,020 33,252 43,629 $755,544 $688,039 $690,981 $695,512 $555,176
-53- ------------------ (1)The exploration and production segment impaired full cost oil and gas properties by $31 million in 1998 and $6 million in 1997. The entire 1997 write-down was applicable to Canadian operations, while $12 million of the 1998 write-down was applicable to Canadian operations. (2)The gathering, processing, and marketing segment recorded a $3 million write-down of its gas gathering assets under the provision of SFAS 121 in 1997. Note 13 - Supplemental Oil and Gas Information (Unaudited) QMR uses the full cost accounting method for the majority of its oil and gas exploration and development activities. However, as ordered by the Utah Public Service Commission, the successful efforts method of accounting is utilized with respect to costs associated with certain cost of service oil and gas properties managed and developed by Wexpro and regulated for ratemaking purposes. Cost of service oil and gas properties are those properties for which the operations and return on investment are regulated by the Wexpro settlement agreement (see Note 10). Oil and Gas Exploration and Development Activities: The following information is provided with respect to QMR's oil and gas exploration and development activities, located in the United States and Canada. Capitalized Costs - The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation and amortization follow:
December 31, 1999 United States Canada Total (In Thousands) Proved properties $885,333 $58,016 $943,349 Unproved properties 58,248 11,529 69,777 Support equipment and facilities 12,418 990 13,408 955,999 70,535 1,026,534 Accumulated depreciation and amortization 509,976 34,515 544,491 $446,023 $36,020 $482,043 -54- December 31, 1998 United States Canada Total (In Thousands) Proved properties $869,514 $48,723 $918,237 Unproved properties 49,724 12,763 62,487 Support equipment and facilities 13,949 929 14,878 933,187 62,415 995,602 Accumulated depreciation and amortization 469,555 29,163 498,718 $463,632 $33,252 $496,884
December 31, 1997 United States Canada Total (In Thousands) Proved properties $702,427 $41,994 $744,421 Unproved properties 19,200 13,390 32,590 Support equipment and facilities 12,556 888 13,444 734,183 56,272 790,455 Accumulated depreciation and amortization 404,742 12,643 417,385 $329,441 $43,629 $373,070
Unproved Properties - Unproved properties are excluded from amortization until evaluated. A summary of costs excluded from amortization at December 31, 1999, and the period in which these costs were incurred are listed below by cost center:
Year Costs Incurred Total 1999 1998 1997 1996 and Prior (In Thousands) United States Acquisition $45,351 $11,447 $24,203 $1,165 $ 8,536 Exploration 12,897 2,302 2,542 2,078 5,975 58,248 13,749 26,745 3,243 14,511 -55- Canada Acquisition 10,111 281 585 4,327 4,918 Exploration 1,418 145 414 198 661 11,529 426 999 4,525 5,579 $69,777 $14,175 $27,744 $7,768 $20,090
Costs Incurred - The following costs were incurred with respect to oil and gas exploration and development activities:
Year Ended December 31, 1999 United States Canada Total (In Thousands) Property acquisition Unproved $12,547 $ 351 $12,898 Proved 3,746 18 3,764 Exploration 7,467 501 7,968 Development 53,488 3,745 57,233 $77,248 $4,615 $81,863 Year Ended December 31, 1998 United States Canada Total (In Thousands) Property acquisition Unproved $ 29,367 $ 145 $ 29,512 Proved 126,723 3,144 129,867 Exploration 10,055 1,222 11,277 Development 43,090 5,363 48,453 $209,235 $9,874 $219,109 -56- Year Ended December 31, 1997 United States Canada Total (In Thousands) Property acquisition Unproved $4,057 $203 $4,260 Proved 2,155 2,155 Exploration 9,975 1,198 11,173 Development 28,511 4,437 32,948 $44,698 $5,838 $50,536
Results of Operations - Following are the results of operations of QMR's oil and gas exploration and development activities, before corporate overhead and interest expenses. The Company recorded write-downs of its full cost oil and gas properties pursuant to the ceiling limitation in 1998 and 1997.
Year Ended December 31, 1999 United States Canada Total (In Thousands) Revenues $150,159 $ 12,316 $162,475 Production expenses 41,948 3,681 45,629 Depreciation and amortization 57,545 3,512 61,057 Total expenses 99,493 7,193 106,686 Revenues less expenses 50,666 5,123 55,789 Income taxes - Note A 13,616 2,567 16,183 Results of operations before corporate overhead and interest expenses $37,050 $ 2,556 $39,606 -57-
Year Ended December 31, 1998 United States Canada Total (In Thousands) Revenues $125,035 $10,474 $135,509 Production expenses 38,788 3,004 41,792 Depreciation and amortization 49,740 5,275 55,015 Write-down of oil and gas properties 19,000 12,000 31,000 Total expenses 107,528 20,279 127,807 Revenues less expenses 17,507 (9,805) 7,702 Income taxes - Note A 1,191 (4,030) (2,839) Results of operations before corporate overhead and interest expenses $16,316 ($5,775) $10,541
Year Ended December 31, 1997 United States Canada Total (In Thousands) Revenues $126,247 $ 8,813 $135,060 Production expenses 36,922 2,424 39,346 Depreciation and amortization 45,801 5,374 51,175 Write-down of oil and gas properties 6,000 6,000 Total expenses 82,723 13,798 96,521 Revenues less expenses 43,524 (4,985) 38,539 Income taxes - Note A 9,330 (3,025) 6,305 Results of operations before corporate overhead and interest expenses $34,194 ($1,960) $32,234
Note A - Income tax expense has been reduced by nonconventional fuel tax credits of $5,282,000 in 1999, $5,736,000 in 1998, and $6,633,000 in 1997. Estimated Quantities of Proved Oil and Gas Reserves - Estimates of the reserves located in the United States were made by Ryder Scott Company, H. J. Gruy and Associates, Inc., Netherland, Sewell & Associates, and Malkewicz Hueni Associates, Incorporated, independent reservoir engineers. Estimated Canadian reserves were prepared by Gilbert Laustsen Jung Associates Ltd. Reserve estimates -58- are based on a complex and highly interpretive process that is subject to continuous revision as additional production and development-drilling information becomes available. The quantities reported below are based on existing economic and operating conditions at December 31. All oil and gas reserves reported were located in the United States and Canada. The Company does not have any long-term supply contracts with foreign governments or reserves of equity investees.
Natural Gas Oil United States Canada Total United States Canada Total (MMcf) (MBbls) Proved Reserves Balance at January 1, 1997 359,542 24,475 384,017 16,129 2,127 18,256 Revisions of estimates 11,177 (4,635) 6,542 (1,929) (316) (2,245) Extensions and discoveries 24,306 4,366 28,672 669 898 1,567 Purchase of reserves in place 8,166 8,166 351 351 Sale of reserves in place (1,292) (1,292) (450) (3) (453) Production (44,370) (3,072) (47,442) (2,106) (271) (2,377)
Standardized Measure of Future Net Cash Flows Relating to Proved Reserves - Future net cash flows were calculated at December 31 using year-end prices and known contract-price changes. Year-end production costs, development costs and appropriate statutory income tax rates, with consideration of any future tax rates already legislated, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The assumptions used to derive the standardized measure of future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The usefulness of the standardized measure of future net cash flows is impaired because of the reliance on reserve estimates and production schedules that are inherently imprecise. -59-
Year Ended December 31, 1999 United States Canada Total (In Thousands) Future cash inflows - Note A $1,327,070 $107,227 $1,434,297 Future production and development costs (459,625) (31,426) (491,051) Future income tax expenses (181,644) (10,773) (192,417) Future net cash flows 685,801 65,028 750,829 10% annual discount for estimated timing of net cash flows (283,030) (23,365) (306,395) Standardized measure of discounted future net cash flows $402,771 $41,663 $444,434 Year Ended December 31, 1998 United States Canada Total (In Thousands) Future cash inflows - Note A $988,365 $66,873 $1,055,238 Future production and development costs (365,493) (22,784) (388,277) Future income tax expenses (76,935) (76,935) Future net cash flows 545,937 44,089 590,026 10% annual discount for estimated timing of net cash flows (216,505) (14,809) (231,314) Standardized measure of discounted future net cash flows $329,432 $29,280 $358,712 Year Ended December 31, 1997 United States Canada Total (In Thousands) Future cash inflows - Note A $883,723 $68,550 $952,273 Future production and development costs (331,750) (25,066) (356,816) Future income tax expenses (87,948) (87,948) Future net cash flows 464,025 43,484 507,509 10% annual discount for estimated timing of net cash flows (189,326) (14,885) (204,211) Standardized measure of discounted future net cash flows $274,699 $28,599 $303,298
Note A - Future cash inflows attributable to United States proved reserves were increased (reduced) by ($5,691,000), $5,961,000, and $2,698,000 in 1999, 1998, and 1997, respectively, for the effects of hedging contracts. Future cash flows from Canadian proved reserves were increased (reduced) by ($1,763,000), ($12,000), and $311,000, respectively, -60- The principal sources of change in the standardized measure of discounted future net cash flows were:
Year Ended December 31, 1999 1998 1997 (In Thousands) Beginning balance $358,712 $303,298 $395,372 Sales of oil and gas produced, net of production costs (116,846) (93,717) (95,714) Net changes in prices and production costs 163,239 (51,568) (132,738) Extensions and discoveries, less related costs 78,611 24,430 28,964 Revisions of quantity estimates 28,311 (14,583) (5,529) Purchase of reserves in place 3,764 129,867 2,155 Sale of reserves in place (33,043) (540) (3,606) Accretion of discount 35,871 30,330 39,538 Net change in income taxes (62,263) 10,783 69,691 Change in production rate (12,627) 7,543 8,077 Other 705 12,869 (2,912) Net change 85,722 55,414 (92,074) Ending balance $444,434 $358,712 $303,298
Cost of Service Activities: The following information is provided with respect to cost of service oil and gas properties managed and developed by Wexpro and regulated by the Wexpro settlement agreement. Information on the standardized measure of future net cash flows has not been included for cost of service activities as the operations of and return on investment for such properties are regulated by the Wexpro settlement agreement. Capitalized Costs - Capitalized costs for cost of service oil and gas properties and the related amounts of accumulated depreciation and amortization follow:
December 31, 1999 1998 1997 (In Thousands) Proved properties $318,451 $297,809 $270,073 Accumulated depreciation and amortization 180,867 168,236 156,845 $137,584 $129,573 $113,228
Costs Incurred - Costs incurred by Wexpro for cost of service oil and gas producing activities were $21,273,000 in 1999, $26,956,000 in 1998, and $26,837,000 in 1997. -61- Results of Operations - Following are the results of operations of QMR's cost of service activities before corporate overhead and interest expenses.
Year Ended December 31, 1999 1998 1997 (In Thousands) Revenues From unaffiliated companies $ 8,844 $10,025 $14,474 From affiliates - Note A 62,335 58,581 50,020 Total revenues 71,179 68,606 64,494 Production expenses 18,548 22,439 22,280 Depreciation and amortization 12,665 11,379 10,213 Total expenses 31,213 33,818 32,493 Revenues less expenses 39,966 34,788 32,001 Income taxes 14,602 12,441 11,334 Results of operations before corporate overhead and interest expenses $25,364 $22,347 $20,667
Note A - Represents revenues received from Questar Gas pursuant to Wexpro settlement agreement. Estimated Quantities of Proved Oil and Gas Reserves - The following estimates were made by the Company's reservoir engineers. No estimates are available for cost of service proved undeveloped reserves that may exist.
Natural Gas Oil (MMcf) (MBbls) Proved Developed Reserves Balance at January 1, 1997 359,907 3,092 Revisions of estimates 7,240 123 Extensions and discoveries 7,486 419 Production (37,454) (585) Balance at December 31, 1997 337,179 3,049 Revisions of estimates 15,017 (46) Extensions and discoveries 25,077 333 Production (37,138) (613) Balance at December 31, 1998 340,135 2,723 Revisions of estimates 5,699 976 Extensions and discoveries 46,739 213 Production (38,890) (623) Balance at December 31, 1999 353,683 3,289
-62- ITEM 14. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not Applicable ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS (a)Reference is made to the Index to Consolidated Financial Statements and Supplementary Data appearing at Item 13. Financial Statements and Supplementary Data of this Form. (b)The following is an Index of Exhibits required by Item 601 of Regulation S-K filed with the Securities and Exchange Commission as part of this Form: Exhibit Number Description 3.1.* Articles of Incorporation dated April 27, 1988 for Utah Entrada Industries, Inc. 3.2.* Articles of Merger, dated May 20, 1988, of Entrada Industries, Inc., a Delaware corporation and Utah Entrada Industries, Inc, a Utah corporation. 3.3.* Articles of Amendment dated August 31, 1998, changing the name of Entrada Industries, Inc. to Questar Market Resources, Inc. 3.4.* Bylaws (as amended effective February 8, 2000). 4.1.*1 U.S. Credit Agreement, dated April 19, 1999, by and among Questar Market Resources, Inc., as U.S. borrower, NationsBank, N.A., as U.S. agent, and certain financial institutions, as lenders, with the First Amendment dated May 17, 1999, the Second Amendment dated July 30, 1999, the Third Amendment dated November 30, 1999, the Fourth Amendment dated April 17, 2000, and the Fifth Amendment dated October 6, 2000. 4.2. Long-term debt instruments with principal amounts not exceeding 10% of QMR's total consolidated assets are not filed as exhibits to this Report. QMR will furnish a copy of those agreements to the SEC upon its request. 10.1.** Stipulation and Agreement, dated October 14, 1981, executed by Mountain Fuel Supply Company [Questar Gas Company]; Wexpro Company; the Utah Department of Business Regulations, Division of Public Utilities; the Utah Committee of Consumer Services; and the staff of the Public Service Commission of Wyoming. (Exhibit No. 10(a) to Questar Gas Company's Form 10-K Annual Report for 1981.) 10.2.*2 Questar Market Resources, Inc. Annual Management Incentive Plan, as amended and restated effective October 26, 2000. 10.3.**2 Questar Corporation Executive Incentive Retirement Plan, as amended and restated effective May 19, 1998. (Exhibit No. 10.2. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 10.4.*2 Questar Corporation Long-Term Stock Incentive Plan, as amended and restated effective October 26, 2000. 10.5.**2 Questar Corporation Executive Severance Compensation Plan, as amended and restated effective May 19, 1998. (Exhibit No. 10.3. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 10.6.*2 Questar Market Resources, Inc. Deferred Compensation Plan for Directors, as amended and restated effective October 26, 2000. 10.7.**2 Questar Corporation Supplemental Executive Retirement Plan, as amended and restated effective June 1, 1998. (Exhibit No. 10.6. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 10.8.**2 Questar Corporation Stock Option Plan for Directors, as amended and restated effective October 29, 1998. (Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended September 30, 1998, filed by Questar Corporation.) 10.9.**2 Form of Individual Indemnification Agreement dated February 9, 1993 between Questar Corporation and directors, including directors of Questar Market Resources, Inc. (Exhibit No. 10.11. to Form 10-K Annual Report for 1992 filed by Questar Corporation.) 10.10.**2 Questar Corporation Deferred Share Plan, as amended and restated effective May 19, 1998. (Exhibit No. 10.7. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 10.11.**2 Questar Corporation Deferred Compensation Plan, as amended and restated effective May 19, 1998. (Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 10.12.**2 Questar Corporation Directors' Stock Plan as approved May 21, 1996. (Exhibit No. 10.15. to Form 10-Q Report for Quarter ended June 30, 1996, filed by Questar Corporation.) 10.13.**2 Questar Corporation Deferred Share Make-Up Plan. (Exhibit No. 10.8. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 10.14.**2 Questar Corporation Special Situation Retirement Plan. (Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 12.* Ratio of Earnings to Fixed Charges. 27.* Financial Data Schedule. ________________________ * Filed previously. ** Exhibits so marked have been filed with the Securities and Exchange Commission as part of the indicated filing and are incorporated herein by reference. 1 Only Annex I and Schedule I to the U.S. Credit Agreement, the Fourth Amendment, and the Fifth Amendment are included. Other items filed previously. 2 Exhibit so marked is a management contract or compensation plan or arrangement. -64- SIGNATURES Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized. QUESTAR MARKET RESOURCES, INC. BY: /s/ G. L. Nordloh G. L. NORDLOH PRESIDENT AND CEO Date: January 10, 2001 -65- EXHIBIT INDEX Exhibit Number Description 3.1.* Articles of Incorporation dated April 27, 1988 for Utah Entrada Industries, Inc. 3.2.* Articles of Merger, dated May 20, 1988, of Entrada Industries, Inc., a Delaware corporation and Utah Entrada Industries, Inc, a Utah corporation. 3.3.* Articles of Amendment dated August 31, 1998, changing the name of Entrada Industries, Inc. to Questar Market Resources, Inc. 3.4.* Bylaws (as amended effective February 8, 2000). 4.1.*1 U.S. Credit Agreement, dated April 19, 1999, by and among Questar Market Resources, Inc., as U.S. borrower, NationsBank, N.A., as U.S. agent, and certain financial institutions, as lenders, with the First Amendment dated May 17, 1999, the Second Amendment dated July 30, 1999, the Third Amendment dated November 30, 1999, the Fourth Amendment dated April 17, 2000, and the Fifth Amendment dated October 6, 2000. 4.2. Long-term debt instruments with principal amounts not exceeding 10% of QMR's total consolidated assets are not filed as exhibits to this Report. QMR will furnish a copy of those agreements to the SEC upon its request. 10.1.** Stipulation and Agreement, dated October 14, 1981, executed by Mountain Fuel Supply Company [Questar Gas Company]; Wexpro Company; the Utah Department of Business Regulations, Division of Public Utilities; the Utah Committee of Consumer Services; and the staff of the Public Service Commission of Wyoming. (Exhibit No. 10(a) to Questar Gas Company's Form 10-K Annual Report for 1981.) 10.2.*2 Questar Market Resources, Inc. Annual Management Incentive Plan, as amended and restated effective October 26, 2000. 10.3.**2 Questar Corporation Executive Incentive Retirement Plan, as amended and restated effective May 19, 1998. (Exhibit No. 10.2. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 10.4.*2 Questar Corporation Long-Term Stock Incentive Plan, as amended and restated effective October 26, 2000. 10.5.**2 Questar Corporation Executive Severance Compensation Plan, as amended and restated effective May 19, 1998. (Exhibit No. 10.3. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 10.6.*2 Questar Market Resources, Inc. Deferred Compensation Plan for Directors, as amended and restated effective October 26, 2000. 10.7.**2 Questar Corporation Supplemental Executive Retirement Plan, as amended and restated effective June 1, 1998. (Exhibit No. 10.6. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 10.8.**2 Questar Corporation Stock Option Plan for Directors, as amended and restated effective October 29, 1998. (Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended September 30, 1998, filed by Questar Corporation.) 10.9.**2 Form of Individual Indemnification Agreement dated February 9, 1993 between Questar Corporation and directors, including directors of Questar Market Resources, Inc. (Exhibit No. 10.11. to Form 10-K Annual Report for 1992 filed by Questar Corporation.) 10.10.**2 Questar Corporation Deferred Share Plan, as amended and restated effective May 19, 1998. (Exhibit No. 10.7. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 10.11.**2 Questar Corporation Deferred Compensation Plan, as amended and restated effective May 19, 1998. (Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 10.12.**2 Questar Corporation Directors' Stock Plan as approved May 21, 1996. (Exhibit No. 10.15. to Form 10-Q Report for Quarter ended June 30, 1996, filed by Questar Corporation.) 10.13.**2 Questar Corporation Deferred Share Make-Up Plan. (Exhibit No. 10.8. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 10.14.**2 Questar Corporation Special Situation Retirement Plan. (Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended June 30, 1998, filed by Questar Corporation.) 12.* Ratio of Earnings to Fixed Charges. 27.* Financial Data Schedule. ________________________ * Filed previously. ** Exhibits so marked have been filed with the Securities and Exchange Commission as part of the indicated filing and are incorporated herein by reference. 1 Only Annex I and Schedule I to the U.S. Credit Agreement, the Fourth Amendment, and the Fifth Amendment are included. Other items filed previously. 2 Exhibit so marked is a management contract or compensation plan or arrangement. -67-