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TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002 OR
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO

Commission File No. 0-30321

QUESTAR MARKET RESOURCES, INC.
(Exact name of registrant as specified in its charter)

State of Utah (State or other jurisdiction of incorporation or organization)		87-0287750 (I.R.S. Employer Identification No.)
180 East 100 South, P.O. Box 45601, Salt Lake City, Utah (Address of principal executive offices)		84145-0601 (Zip code)
Registrant's telephone number, including area code: (801) 324-2600

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
None

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Common Stock, $1.00 Par Value

SECURITIES REGISTERED PURSUANT TO THE SECURITIES ACT OF 1933:
7¹/2% Notes Due 2011
7% Notes Due 2007

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

State the aggregate market value of the voting stock held by nonaffiliates of the registrant as of February 28, 2003. $0.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of February 28, 2003: 4,309,427 shares of Common Stock, $1.00 par value. (All shares are owned by Questar Corporation.)

Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K Report with the reduced disclosure format.

TABLE OF CONTENTS

Heading
PART I
Item 1.		BUSINESS
		General
		Gas and Oil Exploration and Production
		Cost-of-Service Development
		Gathering, Processing, Marketing and Risk Management
		Regulation
		Competition and Customers
		Relationships with Affiliates
		Employees
Item 2.		PROPERTIES
Item 3.		LEGAL PROCEEDINGS
Item 4.		SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PART II
Item 5.		MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Item 6.		(Omitted)
Item 7.		MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
Item 7A.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 8.		FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 9.		CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
PART III
Items 10-13.		(Omitted)
PART IV
Item 14.		EXHIBITS AND REPORTS ON FORM 8-K
GLOSSARY
SIGNATURES

FORM 10-K

ANNUAL REPORT, 2002

PART I

ITEM 1. BUSINESS.

General

Questar Market Resources, Inc. (the "Company" or "QMR," which is a reference that includes the Company's subsidiaries) is a wholly owned subsidiary of Questar Corporation ("Questar"), which is a publicly traded and integrated natural gas company. Questar has two principal business units—Regulated Services and Market Resources. QMR and its subsidiaries comprise the Market Resources unit of Questar and engage in gas and oil exploration, development and production; gas gathering and processing; wholesale gas and hydrocarbon liquids marketing, risk management, and natural gas storage.

QMR is a subholding company that conducts business through Wexpro Company ("Wexpro"), Questar Exploration and Production Company ("Questar E&P"), Questar Gas Management Company ("QGM"), and Questar Energy Trading Company ("QET"). The corporate organization is shown in the following chart.

The Market Resources unit is the primary growth area within the Company. Over the next five years, Questar expects to spend approximately 60 percent of its total capital budget in Market Resources, primarily to expand gas and oil reserves through drilling and acquisitions; enlarge an infrastructure of gathering systems, processing plants, and storage facilities; and continue risk management activities. The diversity of activities within the group enhances a basic strategy to pursue complementary growth. As Questar E&P, for example, finds and acquires new reserves, QGM will have opportunities to expand gathering and processing activities, and QET will have more physical production to support its marketing and storage programs.

Business Strategy. QMR has the following strategies in its business:

•: pursue a disciplined acquisition and exploitation program that grows reserves and production at attractive finding and development costs;
•: expand and exploit a portfolio of quality drilling prospects;
•: deliver industry-leading returns on assets and shareholder equity;
•: hedge up to 75 percent of equity production to meet earnings and growth targets while protecting against downside commodity price risk;
•: maintain a strong balance sheet to fund future acquisitions as opportunities arise;
•: evaluate and implement the latest proven technology to enhance performance and reduce costs; and
•: protect the environment and the health and safety of employees, customers and the communities in which the Company operates.

QMR's activities are described below:

Gas and Oil Exploration and Production.

Questar E&P conducts a blended program of low-cost development drilling and low-risk reserve acquisition. It has a large inventory of proved undeveloped properties. It will continue to identify promising exploration prospects and farm them out to entities that are willing to assume the initial drilling risks. (Under farm out arrangements, a party agrees to assume the risk and financial responsibility for initial drilling in order to acquire an economic interest in the underlying leases and resulting production.)

Questar E&P also maintains a geographical balance and diversity, while focusing its activities in core areas where it has accumulated geological knowledge and has significant expertise. Core areas of activity are the Rocky Mountain region, primarily in Wyoming, Utah and Colorado; and the Midcontinent region, primarily in Oklahoma, Texas, Louisiana and Arkansas. During 2002, QMR sold nonstrategic properties in western Canada and the San Juan Basin of northwestern New Mexico and southwestern Colorado.

Pinedale Anticline. QMR's Pinedale activities in 2002 continue to merit special emphasis. As of year-end 2002, Questar E&P and Wexpro reported 51 producing wells and two awaiting completion or drilling. Drilling results and initial production tests confirmed reserve expectations of 4.8 to 8.0 Bcfe per well, depending on location and the number of formations drilled. As of December 31, 2002, the production capacity from the 51 QMR wells in Pinedale was estimated at 126 million cubic feet of gas equivalent ("MMcfe"), compared to 79 MMcfe as of the period a year earlier. (See the Glossary of Commonly Used Gas and Oil Terms immediately prior to the signature pages.)

Questar E&P and Wexpro conduct drilling activities in Pinedale when government restrictions and weather conditions permit. On a combined basis, they have an approximate 60 percent average working

interest in 14,800 acres in the Mesa Area of the Pinedale Anticline. The original Pinedale drilling program projected 135 to 150 locations, based on 80-acre spacing. The number of potential locations doubled when QMR determined that it was appropriate to drill on the basis of 40-acre spacing. Given the "tight" nature of the sands at Pinedale, QMR is reviewing the economic possibilities of moving to 20-acre spacing.

QMR's activities in Pinedale illustrate its long-term approach. The underlying leasehold acreage was held by production as a result of three wells drilled much earlier. Pinedale gas reserves are contained in tight sands with low permeability. While Questar E&P and Wexpro recognized the presence of gas at Pinedale, they did not drill additional wells on the leases until other companies developed new well completion techniques that hydraulically fractured tight sandstone formations over multiple intervals and successfully used such techniques to complete wells in similar tight reservoirs in a nearby field.

Recently, Questar E&P and Wexpro have established production in the Mesaverde Formation that is geologically similar and immediately beneath the Lance Formation. It is expensive to drill wells in Pinedale; the cost reflects the completion depth of the wells, the need for special handling and multiple stimulations, and governmental orders that impose surface-use limitations and restrict drilling activities to the period between May and December.

Uinta Basin. During 2002, QMR aggressively developed the Uinta Basin properties in eastern Utah obtained with the mid-2001 acquisition of Shenandoah Energy, Inc. ("SEI"). QMR drilled or participated in 150 wells in this region during 2002 and increased gross operated production capacity to 107 MMcf of natural gas per day by year-end 2002. Financial results were negatively affected by low prices that forced curtailment of production during part of the year. Questar E&P plans to continue drilling activities to maintain current production volumes and will pursue additional drilling to target unrecovered oil volumes from the Green River Formation in addition to gas volumes from the deeper Wasatch Formation. It will also evaluate the deeper potential in the underlying Mancos and Blackhawk formations.

Natural Gas Focused. Natural gas remains the primary focus of the Company's E&P operations. As of year-end 2002, the Company had proved reserves (excluding cost-of-service reserves) of 950.4 billion cubic feet ("Bcf") of gas and 27.2 million barrels ("MMbbls") of oil and natural gas liquids ("NGL"), compared to 998.0 Bcf of gas and 31.1 MMbbls of oil and NGL as of the same date in 2001. (The 2001 numbers include Canadian reserves. When Canadian reserves are excluded, the Company had 936.1 Bcf of gas and 27.7 MMbbls of oil and NGL at year-end 2001.) On an energy-equivalent ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of crude oil, natural gas comprised approximately 85.4 percent of proved reserves (excluding cost-of-service reserves) at year end 2002. Proved developed gas reserves constituted 56.9 percent of the total non-regulated proved gas reserves reported. See Note 12 of the Notes to Consolidated Financial Statements under Item 8 of this report for additional information concerning QMR's reserves.

The Questar E&P group's gas production increased from 70.6 Bcf in 2001 to 79.7 Bcf in 2002, despite self-imposed curtailments reflecting low Rockies prices. The increase in production was attributable to expanded development activities, which more than offset the natural decline in some producing areas and the sale of producing reserves. Questar E&P received an average realized selling price of $2.58 per Mcf in 2002, compared to $3.21 per Mcf in 2001. (Realized prices reflect hedging activities.)

Gas volumes are produced from two primary regions—the Midcontinent area and the Rocky Mountain area. Production from each of these areas is generally priced below the Henry Hub pricing center in Louisiana, reflecting demand and access to transportation, but prices were significantly higher in the Midcontinent area than in the Rocky Mountains.

Prices for Rocky Mountain gas volumes declined significantly in the second and third quarters of 2002, reflecting a basis differential of more than $2 per Mcf, compared to the normal basis differential of $.40-$.60 per Mcf. Prices fell to as low as $.72 per Mcf net-to-the-well for some gas volumes, causing Questar E&P to shut in production. The increase in basis differential resulted from an increase in production volumes in the Rocky Mountain area with no expansion of transportation capacity to markets outside the region. Kern River Gas Transmission Company ("Kern River") is currently expanding its pipeline system that transports gas from southwestern Wyoming to California markets. This expansion is scheduled to be in service by mid-2003 and should relieve the problem for the next several years.

Questar E&P continued to generate Section 29 tax credits during 2002, which was the last year that such credits were available under current law. These tax credits are available for production from wells that meet specified criteria, including a requirement that drilling of the wells was commenced prior to January 1, 1993. Eligible properties are often referred to as "tight sands," "coal seams," or "low permeability formations" from which it is generally less economic to produce gas. During 2002, Questar E&P recorded $4.9 million in Section 29 credits, compared to $5.0 million in 2001.

Other Information.

During 2002, Questar E&P produced 2.8 MMbbls of oil and NGL, compared to 2.5 MMbbls in 2001. The production was sold at an average net-to-the-well realized price of $20.39 per barrel in 2002, compared to $19.22 per barrel in 2001. These prices reflect hedges; unhedged prices for crude oil were higher than hedged prices in 2002 ($22.93 per barrel compared to $20.39 per barrel.)

Questar E&P maintains regional offices in Denver, Colorado and Tulsa and Oklahoma City, Oklahoma, in addition to its primary office in Salt Lake City, Utah.

Cost-of-Service Development

QMR subsidiary Wexpro develops and produces gas supplies on certain producing properties owned by Questar's retail distribution utility, Questar Gas, in exchange for reimbursement of costs and a specified return on investment in successful gas wells. Wexpro was incorporated in 1976 as a subsidiary of Questar Gas. Questar Gas's 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.

Wexpro, unlike Questar E&P, does not acquire leasehold acreage for exploration activities. It conducts gas and oil development and production activities on certain producing properties located in the Rocky Mountain region under the terms of the settlement agreement. (The terms of the settlement agreement are described in Note 10 of the Notes to Consolidated Financial Statements under Item 8.) Wexpro produces gas from specified properties for Questar Gas and is reimbursed for its costs plus a return on its successful investment. The after-tax return, which is calculated on net investment adjusted for working capital and deferral taxes, averaged 20.5 percent in 2002. Wexpro's allowed return is adjusted annually based on a specified formula in the settlement agreement. At year-end 2002, Wexpro's net investment base adjusted for working capital and deferred taxes was $164.5 million compared to $161.3 million at year-end 2001. 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 and experts retained by these agencies.

The gas volumes produced by Wexpro for Questar Gas are reflected in the latter's rates at cost-of-service prices. Cost-of-service gas plus the gas attributable to royalty interest owners produced by Wexpro satisfied 45 percent of Questar Gas's system requirements during 2002. Questar Gas relies upon Wexpro's drilling program to develop the properties from which the cost-of-service gas is

produced. During 2002, the average wellhead cost of Questar Gas's cost-of-service gas (net of revenue credits) was $2.16 per Dth, which was lower than Questar Gas's average price for field-purchased gas.

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. In 2002, Wexpro produced 44.2 Bcfe of natural gas and hydrocarbon liquids from Questar Gas's cost-of-service properties and added reserves of 58.7 Bcfe through drilling activities and reserve estimate revisions.

Wexpro, under the terms of the Wexpro agreement, owns oil-producing properties. The revenues from the sale of crude oil produced from such properties are used to recover operating expenses and provide Wexpro with a return on its investment. In addition, Wexpro receives 46 percent of any residual income. (The remaining income is received by Questar Gas and is used to reduce natural gas costs reflected in customer rates.)

Wexpro has an ownership interest in the wells and 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 (a date specified by the settlement agreement referred to above).

Wexpro maintains an office in Rock Springs, Wyoming, in addition to its principal office in Salt Lake City, Utah.

Gathering, Processing, Marketing and Risk Management.

QGM conducts gathering and processing activities in the Rocky Mountain and Midcontinent areas. Its activities are not subject to regulation by the Federal Energy Regulatory Commission (the "FERC") because 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.

The year 2002 was the first full year of operation for Rendezvous Gas Services ("Rendezvous"), which is a joint venture that was developed by QGM and Western Gas Resources, Inc. ("Western Gas") to build and operate new gathering and compression facilities in the Green River Basin of southwestern Wyoming. This basin includes the Pinedale Anticline area in which Questar E&P and Wexpro have developed reserves as well as the Jonah field and other producing areas south of Pinedale. Rendezvous delivers gas volumes from this area for processing and blending to the Blacks Fork plant owned by QGM and to the nearby Granger plant owned by an affiliate of Western Gas.

In late 2002, QGM purchased the remaining 50 percent interest in the Blacks Fork processing plant that has a daily capacity of 84 MMcf and could be expanded to handle additional volumes gathered by Rendezvous. A processing plant strips NGL such as ethane, propane and butane from natural gas volumes to enable the producers to meet pipeline specifications for their gas volumes and to capitalize on historically higher prices for NGL when compared to equivalent volumes of natural gas. QGM recovered 23.4 million gallons (MMgal) of product in 2002 compared to 18.2 MMgal in 2001. QGM and Wexpro jointly own a processing facility located in the Canyon Creek area of southwestern Wyoming that has processing capacity of 43 MMcf per day. QGM also owns interests in several other processing plants in the Rocky Mountain and Midcontinent areas. As a consequence of a 2002 merger with an affiliate, QGM currently is responsible for the gathering and processing operations in the Uinta Basin of eastern Utah.

The majority of QGM's gathering systems were originally built as part of a regulated enterprise. They consist of 1,411 miles of gathering lines, compressor stations, field dehydration plants and measuring stations and were largely built to gather production from Questar Gas's cost-of-service properties. Under a contract with Questar Gas, QGM is obligated to gather the cost-of-service production for the life of the properties. During 2002, QGM gathered 40.7 MMdth of cost-of-service gas for Questar Gas, compared to 37.2 MMdth in 2001.

QGM also gathers gas for affiliates within QMR and for nonaffiliated customers. During 2002, QGM gathered 38.1 MMdth for QMR affiliates, compared to 27.0 MMdth in 2001, and gathered 112.2 MMdth for nonaffiliated customers, compared to 91.7 MMdth in 2001. (These numbers do not include any gas volumes for Rendezvous.)

QET conducts energy marketing activities. It combines gas volumes purchased from third parties and equity production (production that is owned by affiliates) to build a flexible and reliable portfolio. QET aggregates supplies of natural gas for delivery to large customers, including industrial users, municipalities, and other marketing entities. During 2002, QET marketed a total of 83.8 equivalent MMdth ("EMMdth") of third-party natural gas, compared to 91.8 EMMdth in 2001 and earned a margin of $.199 per equivalent Dth, compared to $.149 per equivalent Dth in 2001.

QET uses financial derivatives as a risk management tool to provide price protection for physical transactions involving equity production and marketing transactions. It executed hedges for equity production on behalf of the Questar E&P group with a variety of contracts for different periods of time with a number of counterparties, primarily banks. QET does not engage in speculative hedging transactions. (See Notes 1 and 5 of the Notes to Consolidated Financial Statements included in Item 8 of this report for additional information relating to hedging activities.)

As a wholesale marketing entity, QET concentrates on markets in the Pacific Northwest, Rocky Mountains, and Midwest that are close to reserves owned by affiliates or accessible by major pipelines. It has contracted for firm-transportation capacity on pipelines and firm-storage capacity at Clay Basin.

QET, through a limited liability company in which it has a 75 percent interest, operates the Clear Creek storage facility located in southwestern Wyoming. This facility has 3 Bcf of working gas capacity and is connected with pipelines owned by Questar Pipeline, Overthrust Pipeline Company, The Williams Companies, and Kern River.

Regulation

QMR's operations are subject to various levels of government controls and regulation in the United States at the federal, state, and local levels. Such regulation includes requiring permits for the drilling and production of wells; maintaining bonding requirements in order to drill or operate wells; submitting and implementing spill prevention plans; filing notices relating to the presence, use and release of specified contaminants incidental to gas and oil production; and regulating the location of wells, the method of drilling and casing wells, surface usage and restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transportation of production. The Company's operations are also subject to various conservation matters, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, and the unitization or pooling of gas and oil properties. State conservation laws establish the maximum rates of production from gas and oil wells, generally prohibit the venting or flaring of gas and impose requirements for the ratable purchase of production.

Some of QMR's leases, including many of its leases in the Rocky Mountain area, are granted by the federal government and administered by federal agencies. These leases require compliance with detailed regulations on such things as drilling and operations and the calculation and payment of royalties.

Various federal, state and local environmental laws and regulations affect the Company's operations and costs. These laws and regulations concern the generation, storage, transportation, disposal or discharge of contaminants into the environment and the general protection of public health, natural resources, wildlife, and the environment. They also impose substantial liabilities for any failure on the part of the Company to comply with them.

Competition and Customers

QMR faces competition in all aspects of its business including the acquisition of reserves and leases; obtaining goods, services, and labor; and marketing its production. Its competitors include multinational energy companies and other independent producers, many of which have greater financial resources than QMR.

QMR's business activities can be subject to seasonal variations. Historically, the demand for natural gas decreases during the summer months and increases during the winter months. Weather (both in terms of temperatures and moisture) can have dramatic impacts on natural gas prices and QMR's operations.

Transportation capacity can also have a significant impact on gas prices. The Rocky Mountain region produces more gas volumes than it can use, making it necessary to transport such volumes to markets outside the region. The lack of pipeline capacity or bottlenecks in pipeline systems can depress prices, as evidenced by the basis differential problems in the second and third quarters of 2002.

Questar E&P sells its natural gas production to a variety of customers including pipelines, gas marketing firms, industrial users, and local distribution companies. QMR vigorously evaluates counterparty risk and may require financial guarantees from parties that fail to meet its credit criteria. QMR's crude volumes are sold to refiners, remarketers and other companies, some of which have pipeline facilities near the producing properties. In the event pipeline facilities are not available, crude oil is trucked to storage, refining, or pipeline facilities.

Relationships with Affiliates

The subsidiaries of QMR have important relationships with their affiliates as described above. Questar provides certain administrative services, e.g., public and government relations, financial and audit, to QMR and other members of the consolidated group. Questar, as a general rule, also sponsors the qualified and welfare plans in which QMR's employees participate. (Some QMR employees are not eligible to participate in the defined benefit Retirement Plan sponsored by Questar.) Each of the Company's subsidiaries is responsible for a proportionate share of the costs associated with these services and benefit plans.

Employees

As of December 31, 2002, QMR had 578 employees in the United States, compared to 581 at year-end 2001. None of these employees is represented under collective bargaining agreements. Employee relations are generally deemed to be satisfactory. QMR also periodically engages independent consulting petroleum engineers, environmental professionals, geologists, geophysicists, landmen and attorneys on a fee basis.

ITEM 2. PROPERTIES.

Reserves. The following table sets forth Questar E&P's estimated proved reserves, the estimated future net revenues from the reserves and the standardized measure of discounted net cash flows as of December 31, 2002. These proved reserve volumes do not include cost-of-service reserves managed and developed by Wexpro on behalf of Questar Gas. QMR's reserves were collectively estimated by Ryder Scott Company; H. J. Gruy and Associates, Inc.; Netherland, Sewell & Associates, Inc.; and Malkewicz Hueni Associates, Inc., 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. All properties are located in the United States due to the sale of Canadian properties in the last half of 2002.

		December 31, 2002
Estimated proved reserves
	Natural gas (Bcf)		950.4
	Oil and NGL (MMbbls)		27.2
Total proved reserves (Bcfe)			1,113.4
Proved developed reserves (Bcfe)			660.0
Estimated future net revenues before future income taxes (in thousands)(1)		$	2,576,332
Standardized measure of discounted net cash flows (in thousands)(2)		$	899,626

(1): Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, using average year-end 2002 prices of $3.34 per Mcf for natural gas and $28.46 per barrel for oil and NGL, 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 percent.

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 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 are estimates.

Reference should be made to Note 12 of the Notes to Consolidated Financial Statements included in Item 8 of this report 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.

QMR will file estimated reserves as of December 31, 2002, with the Energy Information Administration in the Department of Energy on Form EIA-23. Although QMR uses the same technical and economic assumptions when it prepares the EIA-23, it is obligated to report reserves for wells it operates, not for all wells in which it has an interest, and to include the reserves attributable to other owners in such wells.

The following charts illustrate QMR's reserve statistics for the years ended December 31, 1998 through 2002:

Gas and Oil Reserves (Bcfe)*

Year	Year-End Proved Reserves	Annual Production	Reserve Life (Years)
1998	574.1	65.3	8.8
1999	597.6	76.6	7.8
2000	730.1	82.3	8.9
2001	1,184.4	85.6	13.8
2002	1,113.4	96.3	11.6

*: Does not include cost-of-service reserves managed and developed by Wexpro on behalf of Questar Gas.

Proportion of Proved Developed to Proved Reserves
and Proportion of Gas Reserves (Bcfe)*

Year	Total Proved Reserves	Proved Developed Reserves	Proved Developed Percent of Total		Natural Gas Percentage of Proved Reserves
1998	574.1	506.0	88	%	85	%
1999	597.6	503.9	84	%	86	%
2000	730.1	566.4	78	%	88	%
2001	1,184.4	719.7	61	%	84	%
2002	1,113.4	660.0	59	%	85	%

*: Does not include cost-of-service reserves managed and developed by Wexpro on behalf of Questar Gas.

Geographic Diversity of Producing Properties

The following table summarizes proved reserves by the Company's major operating areas at December 31, 2002:

	Proved Reserves*	Percent of Total
	(Bcfe)
Midcontinent	273.5	25	%
Rocky Mountain Region
(exclusive of Pinedale and Uinta Basin)	128.7	11	%
Pinedale Anticline	321.1	29	%
Uinta Basin	390.1	35	%

	1,113.4	100	%

*: Does not include cost-of-service reserves managed and developed by Wexpro on behalf of Questar Gas.

Production. The following table sets forth the Company's net production volumes, the average sales prices per Mcf of gas, per barrel of oil and per barrel of NGL produced, and the production cost per Mcfe for the years ended December 31, 2002, 2001, and 2000, respectively. Production costs include direct lifting costs (labor, repairs and maintenance, materials, supplies and workovers), and the costs of administration of production offices, insurance and property and severance taxes, but is exclusive of

depreciation and depletion applicable to capitalized lease acquisitions, exploration and development expenditures.

			Year ended December 31,
			2002		2001		2000
United States (excluding cost-of-service activities)
	Volumes produced and sold
		Gas (Bcf)		74.9		63.9		61.7
		Oil and NGL (MMbbl)		2.3		1.8		1.5
	Average realized selling price (includes hedges)
		Gas (per Mcf)	$	2.61	$	3.21	$	2.80
		Oil and NGL (per Bbl)		20.26		18.14		19.61
	Average selling price (without hedges)
		Gas (per Mcf)	$	2.17	$	3.83	$	3.32
		Oil and NGL (per Bbl)		23.31		23.45		27.66
	Production costs per Mcfe
		Lease operating expense	$	.51	$	.55	$	.42
		Production taxes		.20		.29		.27

		Production cost per Mcfe	$	.71	$	.84	$	.69

			Year ended December 31,
			2002		2001		2000
Canada
	Volumes produced and sold
		Gas (Bcf)		4.8		6.7		7.3
		Oil and NGL (MMbbls)		.5		.7		.7
	Average realized selling price (includes hedges)(1)
		Gas (per Mcf)	$	2.22	$	3.25	$	2.83
		Oil and NGL (per Bbl)		21.03		21.98		22.29
	Average selling price (without hedges)(1)
		Gas (per Mcf)	$	2.22	$	3.98	$	3.05
		Oil and NGL (per Bbl)		21.03		22.35		27.15
	Production costs per Mcfe(1)
		Lease operating expense	$	.92	$	.74	$	.72
		Production taxes						.03

		Production cost per Mcfe	$	.92	$	.74	$	.75

Cost of Service (Wexpro-operated)
	Volumes produced
		Gas (Bcf)		41.2		37.9		41.5
		Oil and NGL (MMbbl)		.5		.5		.6

(1): In United States dollars.

Productive Wells. The following table summarizes the Company's productive wells as of December 31, 2002.(1)(2)
All of these wells are located in the United States.

Gas Wells				Oil Wells				Total Wells
Gross		Net		Gross		Net		Gross		Net
3,427		1,598		885		485		4,312		2,083

(1): Although many of the Company's wells produce both gas and oil, a well is categorized as either a gas well or an oil well based upon the ratio of gas to oil production volumes.
(2): Each well completed to more than one producing zone is counted as a single well. There were 55 gross wells with multiple completions.

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.

Leasehold Acreage. The following table summarizes developed and undeveloped leasehold acreage in which the Company owns a working interest as of December 31, 2002. "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, 2002

			Developed(1)		Undeveloped(2)		Total
			Gross	Net	Gross	Net	Gross	Net
United States
	Arizona		—	—	480	450	480	450
	Arkansas		32,322	10,513	510	400	32,832	10,913
	California		344	112	3,376	1,137	3,720	1,249
	Colorado		160,594	111,941	218,306	96,979	378,900	208,920
	Idaho		—	—	44,174	10,642	44,174	10,642
	Illinois		172	39	14,267	3,989	14,439	4,028
	Indiana		—	—	1,620	466	1,620	466
	Kansas		134	134	16,000	3,772	16,134	3,906
	Kentucky		—	—	13,723	5,468	13,723	5,468
	Louisiana		14,436	9,186	1,230	1,170	15,666	10,356
	Michigan		—	—	6,200	1,266	6,200	1,266
	Minnesota		—	—	313	104	313	104
	Mississippi		2,862	1,902	1,334	668	4,196	2,570
	Montana		25,285	10,186	308,989	56,590	334,274	66,776
	Nevada		320	280	680	542	1,000	822
	New Mexico		84,273	67,066	36,101	14,879	120,374	81,945
	North Dakota		1,013	371	144,312	21,532	145,325	21,903
	Ohio		—	—	202	43	202	43
	Oklahoma		1,469,170	258,418	63,678	39,702	1,532,848	298,120
	Oregon		—	—	43,868	7,670	43,868	7,670
	South Dakota		—	—	204,398	107,828	204,398	107,828
	Texas		152,409	50,765	60,254	46,360	212,663	97,125
	Utah		79,046	63,915	250,432	124,190	329,478	188,105
	Washington		—	—	26,631	10,149	26,631	10,149
	West Virginia		969	114	—	—	969	114
	Wyoming		228,757	143,157	441,097	255,565	669,854	398,722

		Total U.S.	2,252,106	728,099	1,902,175	811,561	4,154,281	1,539,660

(1): Developed acres are acres 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.

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, 2003	118,371	49,697
	December 31, 2004	113,767	51,684
	December 31, 2005	82,988	46,863
	December 31, 2006	84,171	43,651
	December 31, 2007 and later	1,502,878	619,666

Drilling Activity. The following table summarizes the number of development and exploratory wells drilled by the QMR, including the cost-of-service wells drilled by Wexpro, during the years indicated.

			Year Ended December 31,
			2002		2001		2000
			Gross	Net	Gross	Net	Gross	Net
Development Wells
	United States
		Completed as natural gas wells	206	143.9	238	110.4	211	79.8
		Completed as oil wells	9	7.0	13	9.6	9	1.4
		Dry holes	5	2.4	11	4.3	12	5.0
		Waiting on completion	29	—	46	—	36	—
		Drilling	6	—	10	—	14	—
	Canada
		Competed as natural gas wells	8	2.1	7	1.8	11	1.1
		Completed as oil wells	1	.2	2	.5	8	2.3
		Dry holes	1	.4	1	.1	2	1.1
		Waiting on completion	1	—	—	—	2	—
		Drilling	—	—	—	—	1	—

Total Development Wells			266	156.0	328	126.7	306	90.7

			2002		2001		2000
			Gross	Net	Gross	Net	Gross	Net
Exploratory Wells
	United States
		Completed as natural gas wells	2	.6	1	.4	—	—
		Dry holes	1	1	1	.4	5	2.0
		Waiting on completion	6	—	—	—	—	—
		Drilling	—	—	—	—	1	—

			2002		2001		2000
			Gross	Net	Gross	Net	Gross	Net
	Canada
		Competed as natural gas wells	1	.5	1	.5	1	.2
		Completed as oil wells	—	—	1	.4	1	.2
		Dry holes	—	—	5	1.9	2	.9
		Drilling	1	—	—	—	—	—

		Total Exploratory Wells	11	2.1	9	3.6	10	3.3

Total Wells			277	158.1	337	130.3	316	94.0

Operation of Properties. The day-to-day operations of gas and oil 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.

When operating wells, Questar E&P and Wexpro receive 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, Questar E&P records the monthly overhead reimbursement as a reduction of general and administrative expense, which is a common industry practice. Wexpro records the reimbursement as a reduction of operating and maintenance expenses subject to the settlement agreement.

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 gas and oil 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.

ITEM 3. LEGAL PROCEEDINGS.

There are various legal proceedings pending against QMR and its affiliates. Management believes that the outcome of these cases will not have a material adverse effect on the Company?s financial position, operating results or liquidity. Significant cases are discussed below.

Grynberg. Questar defendants, including Questar E&P, are involved in three separate lawsuits filed by Jack Grynberg, an independent producer. One case, United States ex rel. Grynberg v. Questar Corp., involves claims filed by Grynberg under the Federal False Claims Act and is substantially similar to other cases filed against pipelines and their affiliates that have all been consolidated for discovery and pre-trial motions in Wyoming's federal district court. The cases involve allegations of industry-wide mismeasurement of natural gas volumes on which royalty payments are due the federal government. Grynberg has filed an appeal from the order issued by the trial judge dismissing his valuation claims from the lawsuits. To sustain claims under the False Claims Act, Grynberg must demonstrate that he is the original source of information concerning the allegations and that he has "direct and independent knowledge" of the claimed mismeasurement practices. The Questar defendants participate in a joint defense group that is attacking Grynberg's eligibility to bring such claims.

On March 21, 2003, the Utah Supreme Court substantially upheld the trial court's order granting summary judgment to the Questar defendants in Grynberg v. Questar Pipeline. This cased involved claims that several Questar defendants mismeasured the heating content of gas volumes attributable to Gynberg's working interest in specified wells located in southwestern Wyoming, committed fraud, and breached fiduciary responsibilities. Specifically, the Court ruled Grynberg's contract claims were time-barred, the economic loss doctrine precludes him from bringing tort claims based on contractual responsibilities, he is not a third party beneficiary of his operator's contracts, Questar defendants do not owe him fiduciary responsibilities, and there was no equitable tolling of the applicable statutes of limitations. The Utah Supreme Court did rule that Grynberg was not collaterally estopped from presenting a contract termination issue that had previously been ruled on by a Wyoming federal district court judge and remanded the case to the trial court to determine whether any contractual claims remain.

The third case, Grynberg and L & R Exploration Venture v. Questar Pipeline Co., is pending in a Wyoming federal district court against Questar defendants. This case involves some of the same allegations that were heard in an earlier case, e.g., breach of contract, intentional interference with a contract, but Grynberg added claims of antitrust and fraud. In June of 2001, the judge entered an order granting the motion for partial summary judgment filed by the Questar defendants dismissing the antitrust claims from the case, but has not ruled on other motions for summary judgment dealing with ratable take and fraud.

Gas Pipelines. Questar E&P, QGM, Wexpro, Questar Gas, and Questar Pipeline are among the numerous defendants in this case, which is currently known as Price v. Gas Pipelines, that has been filed against the pipeline industry. Pending in a Kansas state district court, this case is similar to the cases filed by Grynberg, but the allegations of a conspiracy by the pipeline industry to set standards that result in the systematic mismeasurement of natural gas volumes and resulting underpayment of royalties are made on behalf of private and state lessors, rather than on behalf of the federal government. The numerous defendants are requesting dismissal for lack of personal jurisdiction against any defendants, including most of the named Questar parties, that do not conduct business activities in Kansas. They are also opposing class certification.

QMR Class Action Cases. Royalty class actions are being asserted by landowners against entities involved in the oil and gas production and marketing businesses. The QMR group of companies has been involved in several class actions involving royalty owners and believes it will continue to be the subject of additional class actions involving similar claims.

Environmental Compliance. An Oklahoma agency has advised QGM that it may be violating state air pollution laws in conjunction with its operation of processing facilities in the state by failing to obtain necessary permits, submit proper notices, and pay specified emissions fees.

QMR entities are listed as "responsible parties" for sites involving hazardous wastes. They have also received notices of violation from state environmental agencies. None of these sites is significant to the QMR. With the possible exception of the Oklahoma situation described above, no pending proceeding involving notices of violation involves a penalty of $100,000 or more.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

The Company did not submit any matters to a vote of its sole stockholder during the last quarter of 2002.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

All of the Company's outstanding shares of common stock, $1.00 par value, are owned by Questar. Information concerning the dividends paid on such stock and the ability to pay dividends is reported in the Statements of Common Shareholder's Equity and the Notes to Financial Statements included in Item 8 of this report.

ITEM 6. SELECTED FINANCIAL DATA.

The Company, as the wholly owned subsidiary of a reporting company under the Securities and Exchange Act of 1934, as amended, (the "Act"), is entitled to omit the information requested in this Item.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

RESULTS OF OPERATIONS

Questar Market Resources (QMR or Market Resources) through its subsidiaries conducts gas and oil exploration, development and production, gas gathering and processing, and energy-marketing operations. Primary objectives of energy-marketing operations are to support the company's earnings targets and to protect the company's earnings from adverse commodity-price changes. The company does not enter into energy-hedging contracts for speculative purposes. Wexpro, a subsidiary of QMR,

develops gas and oil reserves owned by an affiliate, Questar Gas. Following is a summary of QMR's financial results and operating information:

				Year Ended December 31,
				2002		2001		2000
				(in thousands)
OPERATING INCOME
Revenues
	Natural gas sales			$	205,928	$	226,656	$	193,359
	Oil and natural gas-liquids sales				67,572		59,482		59,901
	Cost-of-service gas operations				93,177		89,934		74,492
	Energy marketing				218,832		337,845		379,760
	Gas gathering, processing and other				43,614		32,480		34,541

		Total revenues			629,123		746,397		742,053
Operating expenses
	Energy purchases				202,132		324,124		369,752
	Operating and maintenance				131,598		112,087		106,761
	Depreciation, depletion and amortization				117,446		92,678		85,025
	Exploration				6,086		6,986		7,917
	Abandonment and impairment of gas, oil and related properties				11,183		5,171		3,418
	Production and other taxes				28,558		43,125		36,262
	Wexpro Agreement—oil-income sharing				1,676		2,885		4,758

		Total operating expenses			498,679		587,056		613,893

			Operating income	$	130,444	$	159,341	$	128,160

OPERATING STATISTICS
Nonregulated production volumes
	Natural gas (MMcf)				79,674		70,574		68,963
	Oil and natural gas liquids (Mbbl)				2,764		2,500		2,225
	Total production (bcfe)				96.3		85.6		82.3
	Average daily production (MMcfe)				264		234		225
Nonregulated selling price, net to the well
	Average realized selling price (including hedges)
		Natural gas (Mcf)		$	2.58	$	3.21	$	2.80
		Oil and natural gas liquids (bbl)		$	20.39	$	19.22	$	20.50
	Average selling price (without hedges)
		Natural gas (Mcf)		$	2.17	$	3.84	$	3.29
		Oil and natural gas liquids (bbl)		$	22.93	$	23.14	$	27.49
	Wexpro investment base, net of deferred income taxes (in millions)			$	164.5	$	161.3	$	124.8
Energy-marketing volumes (Mdthe)					83,816		91,791		105,632
Natural gas-gathering volumes (Mdth)
	For unaffiliated customers				112,205		91,729		92,969
	For Questar Gas				40,685		37,161		36,791
	For other affiliated customers				38,136		27,049		25,068

		Total gathering			191,026		155,939		154,828

	Gathering revenue (dth)			$	0.16	$	0.13	$	0.13

Exploration and Production Activities

In 2002, QMR grew its nonregulated production by 12% to 96.3 bcfe compared to the previous year's production of 85.6 bcfe. This 12% increase was achieved despite QMR's sale of producing properties and deliberate curtailment of approximately 3.3 bcfe of production due to low prices. However, revenues were lower in 2002. Low prices, primarily for natural gas produced in the Rocky Mountains, plagued QMR for much of 2002. Rockies prices, net to the well, were below $1.50 per Mcf for much of 2002. Approximately 60% of QMR's production comes from the Rockies.

QMR acquired producing properties in the Uinta Basin of Utah in July 2001, which provided a significant portion of the year-to-year production growth. Also, development of the Uinta Basin properties and the Pinedale Anticline in southwestern Wyoming was the prime contributor to production increases in 2002 and 2001.

The basis differential between daily prices in the Rockies and the Henry Hub (Louisiana) at times exceeded $2 per MMBtu, far greater than the historic average of $.40 to $.60. Gas prices in the Rockies have been impacted because transportation capacity out of the region has not kept pace with the region's growing production rate. While this imbalance should be partially remedied with an expansion of the Kern River pipeline, scheduled to begin operation in mid-2003, it may persist for some time. Prices received on production from Midcontinent properties have been much higher. To protect against the possibility that the Rockies basis will again widen in the second and third quarters of 2003, QMR has hedged a substantial portion of its proved-developed production in the Rockies.

QMR's energy hedges partially mitigated poor Rockies gas prices in 2002. QMR hedged or presold approximately 56% of its nonregulated natural gas production and 78% of its nonregulated oil production. As a result, the average realized selling price for natural gas amounted to $2.58 per Mcf and exceeded unhedged prices by $.41 per Mcf. Oil-production hedges reduced the average realized selling price for oil and natural gas liquids (NGL) by $2.54 per barrel. In 2002, hedging activities increased gas revenues by $32.9 million and decreased oil revenues by $7 million. In 2001, hedging activities reduced gas revenues by $44.7 million and oil revenues by $9.8 million. QMR does not hedge its NGL production. A summary of QMR's energy-price hedging positions for nonregulated production as of the fourth-quarter earnings release dated February 12, 2003 follows:

Year	Region	Net revenue interest production under price- hedging contracts Gas (bcf)	Average price net to the well Gas per Mcf
2003	Rocky Mountains	32.1	$	3.04
	Midcontinent	12.0	$	3.60

		44.1	$	3.19
2004	Rocky Mountains	14.5	$	3.11
	Midcontinent	3.4	$	3.71

		17.9	$	3.22
		Oil (Mbbl)	Oil per bbl
2003	All regions	1,095	$	21.80

Lifting cost per Mcfe rose in 2001 due to higher production taxes, which are based on the value of production. The average realized selling price of gas per Mcf decreased 20% in 2002 compared with 2001, and increased 15% in 2001 compared with 2000. The total amount of lease-operating expenses increased 6% in 2002 compared with 2001 and 28% in 2001 compared with 2000 reflecting an increase in the number of producing properties. However, on an Mcfe basis, lease-operating expenses were

down 5% in 2002 versus 2001 and up 26% in 2001 versus 2000, Lease-operating expenses primarily include labor, maintenance, repairs and well workovers.

	For the year ended December 31,
	2002		2001		2000
	Per Mcfe
Lease-operating expense	$	0.55	$	0.58	$	0.46
Production taxes		0.17		0.25		0.24

Lifting cost	$	0.72	$	0.83	$	0.70

Depreciation, depletion and amortization expense (DD&A) increased 27% in 2002 and 9% in 2001 due to increased gas and oil production and higher average rates per Mcfe. The average DD&A rate per Mcfe is a function of the finding cost of adding reserves and the changing market value of those reserves. By definition, reserve quantities that QMR can disclose and use in DD&A calculations are based on existing economic and operating conditions.

	For the year ended December 31,
	2002		2001		2000
	Per Mcfe
Depreciation, depletion and amortization	$	0.91	$	0.83	$	0.78

Exploration expense, largely a function of the number of unsuccessful exploratory wells, decreased 13% in 2002 and 12% in 2001. Abandonments and impairments increased in 2002 primarily due to a write-off of leasehold costs and a $1.9 million write-down of the value of drilling rigs. The four company-owned drilling rigs, acquired in 2001 as part of the Shenandoah Energy, Inc. (SEI) acquisition, were sold in early 2003. Abandonments and impairments are noncash expenses.

Interest and other income

QMR sold its Canadian subsidiary and producing properties in the Midcontinent and San Juan Basin resulting in a $43.2 million pretax gain, $19.7 million of which related to the Canadian subsidiary. In 2001, assets sales generated a $13.9 million pretax gain. The favorable settlement of a lawsuit resulted in $5.6 million of pretax earnings in 2002.

Debt expense

Debt expense was 52% higher in 2002 compared with 2001 primarily due to increased debt to used to fund the purchase of SEI in July of 2001. QMR used proceeds from the sale of assets, which occurred primarily in the fourth quarter of 2002 to reduce debt. The impact of higher debt was partially offset by lower short-term interest rates that approached historical lows. Interest expense was flat in 2001 compared with 2000 due to lower short-term interest rates.

Earnings from unconsolidated affiliates

Pretax earnings from unconsolidated affiliates were $3 million higher in 2002 compared with 2001. Rendezvous LLC began gathering and processing operations in the fourth quarter of 2001 and accounted for approximately a $2 million increase in pretax earnings. QMR's share of pretax earnings from the Blacks Fork partnership increased approximately $1 million in 2002 due to improved gas-processing margins from lower gas prices in the Rockies.

Income taxes

The effective combined federal, state and foreign income tax rate was 35.2% in 2002, 34.9% in 2001 and 33.2% in 2000. Income tax rates were below the combined income rate of about 40% primarily due to nonconventional fuel credits, which amounted to $4.9 million in 2002, $5 million in 2001 and $4.7 million in 2000. Under current law, the federal income tax credit for production from a nonconventional source will be discontinued for production sold after December 31, 2002.

Wexpro Earnings

Wexpro's net income was $2.6 million higher in 2002 as a result of an increased investment base when compared to December 31, 2001. The investment base, net of deferred income taxes and depreciation, grew as a result of successful drilling. Wexpro conducts cost-of-service development of gas reserves owned by Questar Gas. Cost of service refers to Wexpro's contracted entitlement to reimbursement of its costs and an approved return on investment for operating Questar Gas's properties. Oil is sold at market prices. Any net income from oil sales remaining after recovery of expenses and Wexpro's return on investment is shared between Wexpro and Questar Gas. Questar Gas's portion is reported as an expense under oil-income sharing on the income statement.

Gas Gathering and Energy-Marketing Activities

Revenues for gathering and processing were $11.1 million higher in 2002 compared with the same period in 2001 as a result of gathering systems in the Uinta Basin acquired as part of the July 2001 SEI acquisition and increased production in the Rockies. The volume of gas gathered and the average gathering rate both increased 23% over the previous year. Marketing margins improved by $3 million in 2002 compared with 2001 in spite of lower prices and lower marketing volumes in 2002. Marketing volumes were 9% lower in 2002 compared with 2001. The margin represents revenues less purchase and transportation costs.

Nonregulated Gas and Oil Reserves

In 2002, gas and oil reserves declined 6%, after production and sales of producing properties, to 1,113 bcfe. QMR's reserve-replacement ratio was 26% in 2002 and 631% in 2001. In 2001, QMR acquired 415 bcfe of proved gas and oil reserves in the SEI acquisition. Reserve additions, revisions and purchases, and sales in place, amounted to 25 bcfe in 2002 and 540 bcfe in 2001. In 2002, QMR completed the sale of its Canadian subsidiary, and producing properties in the San Juan Basin and other areas. The sales accounted for a 122 bcfe decrease in reserves. Excluding these sales, the 2002 reserve-replacement ratio was 153%.

As a result of the property sales, QMR begins 2003 with a production base of 83 to 85 bcfe.

The five-year average finding cost per Mcfe for the past three years, excluding Wexpro, was $.85 in 2002 and 2001, and $.86 in 2000.

LIQUIDITY AND CAPITAL RESOURCES
Operating Activities

	Year Ended December 31,
	2002		2001		2000
	(in thousands)
Net income	$	97,929	$	101,134	$	77,808
Noncash adjustments to net income		147,041		119,572		108,121
Changes in operating assets and liabilities		16,524		30,592		(54,680	)

Net cash provided from operating activities	$	261,494	$	251,298	$	131,249

Net cash provided from operating activities increased in 2002 compared with 2001 as a result of larger noncash adjustments to income. Net cash provided from operating activities increased 91% in 2001 compared with 2000 as a result of 30% higher net income and collection of accounts receivable and the return of interest-bearing deposits with energy brokers.

Investing Activities

QMR participated in 277 wells (158 net) that resulted in 147 net gas wells, seven net oil wells and four net dry holes. There were 43 gross-count wells in progress at year end. QMR's success rate was 98% in 2002. QMR acquired the remaining 50% interest in the Blacks Fork processing plant in December of 2002. The company invested $12.5 million in the Rendezvous partnership that provides gas gathering and compression services to producers in southwestern Wyoming.

The details of capital expenditures for 2002, 2001 and a forecast of 2003 are as follows:

	Year Ended December 31,
	2003 Forecast		2002		2001
	(in thousands)
Exploratory drilling and other exploration	$	6,200	$	5,966	$	5,523
Development drilling		128,600		112,173		132,440
Wexpro drilling		25,200		24,065		55,651
Reserve acquisitions		65		370,068
Production		13,800		14,191		7,624
Gathering and processing		43,900		31,407		53,914
Storage		4,700		40		11,754
General		2,400		1,453		1,533

	$	224,800	$	189,360	$	638,507

Financing Activities

In 2002, QMR made a concerted effort to reduce debt resulting from the July 2001 acquistion of SEI. Cash flow provided from operations and the sale of assets funded a $119 million reduction of debt, and capital expenditures. In 2002, proceeds from asset dispositions amounted to $158 million. On January 16, 2002, QMR sold $200 million of five-year private placement notes with a 7% interest rate and used the proceeds to repay short-term debt.

In November 2002, Moody's downgraded debt ratings of Questar and subsidiaries one level after completing a review that began May 2, 2002. Moody's established a Baa3 rating for the senior-unsecured debt of QMR. Also, Moody's established a stable outlook for each Questar entity. A lower debt rating may increase the company's cost of debt; however, Moody's revised ratings are solidly

investment grade. The downgrade will not materially affect the company's growth strategy. Standard & Poor's has assigned a BBB+ to debt issued by QMR. Standard & Poor's has a negative outlook, reflecting concerns that the Questar's risk profile may increase with its plan to grow unregulated businesses.

QMR's consolidated capital structure consisted of 49% long-term debt and 51% common shareholder's equity at December 31, 2002.

Critical Accounting Policies

The company's consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States. The preparation of consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. Management believes that the following accounting policies may involve a higher degree of complexity and judgment on the part of management.

Successful Efforts Accounting for Gas and Oil Operations

Under the successful efforts method of accounting, the company capitalizes the costs of leaseholds, development wells, successful exploratory wells and related equipment and facilities. The costs of unsuccessful exploratory wells are charged to expense when it is determined that such wells have not located proved reserves. Unproved leasehold costs are periodically reviewed for impairment. Costs related to impaired prospects are charged to expense. Costs of geological and geophysical studies and other exploratory activities are expensed as incurred. Costs associated with production and general corporate activities are expensed in the period incurred. The company recognizes a gain or loss on the sale of properties on a field basis.

Capitalized proved-leasehold costs are depleted using the unit-of-production method based on proved reserves on a field basis. All other capitalized costs associated with gas and oil properties are depreciated using the unit-of-production method based on proved-developed reserves on a field basis. The company engages independent consultants to help calculate nonregulated gas and oil reserves. Reserve estimates are based on a complex and highly interpretive process that is subject to continuous revision as additional production and development-drilling information becomes available.

Wexpro Agreement

Wexpro's operations are subject to the terms of the Wexpro Agreement. The agreement was effective August 1, 1981, and sets forth the rights of Questar Gas's utility operations to share in the results of Wexpro's successful development operations and the rate of return that Wexpro will earn for managing Questar Gas's reserves. The agreement was approved by the Public Service Commission of Utah (PSCU) and the Public Service Commission of Wyoming (PSCW) in 1981 and affirmed by the Utah Supreme Court in 1983.

Accounting for Derivatives

QMR uses derivative instruments, typically fixed-price swaps, to hedge against a decline in the average selling prices of its gas and oil production. Accounting rules for derivatives require that these instruments be marked to fair value at the balance-sheet reporting date. The difference between fair value and carrying value is reported either in net income or comprehensive income depending on the structure of the derivatives. The company has structured virtually all of its energy-derivative instruments as cash-flow hedges. Any changes in the fair value of cash-flow hedges are recorded on the balance sheet and in comprehensive income or loss until the underlying gas or oil is produced. When a derivative is terminated before its contract expires, the associated gain or loss is recognized in income over the life of the previously hedged production.

Revenue Recognition

Revenues are recognized in the period that services are provided or products are delivered. The company's exploration and production operations use the sales method of accounting for gas revenues, whereby revenue is recognized on all gas sold to purchasers. A liability is recorded to the extent that the company has an imbalance in excess of its share of remaining reserves in an underlying property. Revenue and prices for gas and oil are reported on a "net-to-the-well" basis.

New Accounting Standard

Statement of Financial Accounting Standards (SFAS) 143, "Accounting for Asset Retirement Obligations," was issued in June of 2001. SFAS 143 addresses the financial accounting and reporting of the fair value of legal obligations associated with the retirement of tangible long-lived assets. The new standard requires that plant abandonment costs be estimated at fair value, capitalized and depreciated over the life of the related assets. The new standard will impact recording abandonment costs of gas and oil wells and processing plants. The company has not completed its evaluation of the impact of SFAS 143. However, these expenses are noncash until abandonment takes place. SFAS 143 is effective beginning January 1, 2003.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QMR's primary market-risk exposures arise from commodity-price changes for natural gas, oil and other hydrocarbons and changes in interest rates. QMR sold its Canadian affiliate in the fourth quarter of 2002, eliminating its foreign-exchange risk. A QMR subsidiary has long-term contracts for pipeline capacity for the next several years and is obligated for transportation services with no guarantee that it will be able to recover the full cost of these transportation commitments.

QMR bears a majority of the risk associated with commodity-price changes and uses energy-price-hedging arrangements in the normal course of business to limit the risk of adverse price movements. However, these same arrangements typically limit future gains from favorable price movements. The hedging contracts exist for a significant share of QMR-owned gas and oil production and for a portion of energy-marketing transactions.

Commodity-Price Risk Management

The company has established policies and procedures for managing commodity-price risks through the use of derivatives. The primary objectives of energy price-hedging are to support the company's earnings targets and to protect earnings from downward movements in commodity 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 company's Board of Directors. It is the company's current policy to hedge up to 75% of the current year's proved-developed-production by the first of March in the current year, at or above selling prices that support its budgeted income. The company will add incrementally to these hedges to reach forward beyond the current year when price levels are attractive. The company does not enter into derivative arrangements for speculative purposes and does not hedge undeveloped reserves.

Natural gas prices in the Rocky Mountain region were depressed in 2002. The basis differential, the difference between Rockies prices and the benchmark Henry Hub (Louisiana) price, at times exceeded $2.00 per MMBtu, the widest differential in nearly a decade. This widening basis differential results from a combination of increased regional production, weak seasonal demand, and inadequate capacity in pipelines that transport Rockies gas out of the region. Rockies prices may remain depressed until regional demand increases and/or major new export pipelines are built. The expansion of the Kern River pipeline will improve pipeline capacity out of the Rockies but may not immediately return Rockies basis to historical ranges. With the acquisition of SEI in 2001, increased investment in

development of the company's Pinedale Anticline acreage and sale of Canadian properties, a growing percentage of the company's production is in the Rockies.

Management's attention has been focused on improving Rockies prices by hedging approximately 90% of Rockies 2003 proved-developed-production at an average of $3.04 per Mcf net-to-the-well. In addition, the company may curtail production if prices drop below levels necessary for profitability.

QMR held energy-price hedging contracts covering the price exposure for about 85.2 million dth of gas and 1.1 million bbl of oil as of December 31, 2002. A year earlier QMR hedging contracts covered 70.2 million dth of natural gas and 1.1 million bbl of oil. QMR does not hedge the price of natural gas liquids.

A summary of the activity for the fair value of energy-price hedging contracts for the year ended December 31, 2002, is below. The calculation is comprised of the valuation of financial and physical contracts.

	(in thousands)
Net fair value of energy-hedging contracts outstanding at Dec. 31, 2001	$	50,897
Contracts realized or otherwise settled		(42,362	)
Increase in energy prices on futures markets		(29,196	)

Net fair value of energy-hedging contracts outstanding at Dec. 31, 2002	$	(20,661	)

A vintaging of energy-price hedging contracts as of December 31, 2002, is shown below. About 76% of those contracts will settle and be reclassified from other comprehensive income in the next 12 months.

	(in thousands)
Contracts maturing by Dec. 31, 2003	$	(15,621	)
Contracts maturing between Dec. 31, 2004 and Dec. 31, 2005		(5,047	)
Contracts maturing between Dec. 31, 2005 and Dec. 31, 2006		50
Contracts maturing between Dec. 31, 2006 and Dec. 31, 2008		(43	)

Net fair value of energy-hedging contracts outstanding at Dec. 31, 2002	$	(20,661	)

QMR's mark-to-market valuation of gas and oil price-hedging contracts plus a sensitivity analysis follows:

	As of December 31,
	2002			2001
	(in millions)
Mark-to-market valuation—asset (liability)	$	(20.7	)	$	50.9
Value if market prices of gas and oil decline by 10%		(22.2	)		65.7
Value if market prices of gas and oil increase by 10%		(19.1	)		36.1

The calculations reflect energy prices posted on the NYMEX, various "into-the-pipe" postings, and fixed prices on the indicated dates. These sensitivity calculations do not consider changes in the fair value of the corresponding scheduled physical transactions for price hedges on equity production, (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

QMR held $350 million of fixed rate debt with a fair value of $385.1 million at December 31, 2002. The fair value of fixed rate debt is subject to change as interest rates fluctuate. The company

held floating-rate long-term debt at December 31, 2002 and 2001 amounting to $200 million and $253.9 million, respectively. The book value of variable-rate debt approximates fair value. If interest rates declined by 10%, the annual interest costs paid on variable-rate long-term debt would decrease about $.4 million based on the balance outstanding at December 31, 2002 and $.7 million for the year earlier balance.

Liquidity Accelerators

QMR has commodity-price hedging agreements in place with ten different counterparties. These counterparties are banks and energy-trading firms. In some contracts, the amount of credit allowed before QMR must post collateral for out-of-the-money hedges varies depending on the credit rating assigned to QMR's debt. At QMR's current credit ratings, the credit available from each counterparty ranges between $5 million and $30 million, depending on the agreement. In cases where this arrangement exists, if QMR's credit ratings fall below investment grade (BBB- by Standard & Poor's or Baa2 by Moody's), counterparty credit generally falls to zero.

Business with Energy Merchants

QMR has significant gas sales to energy merchants, some of which have had their debt ratings downgraded. All companies with such concerns were current on their accounts as of the date of this report. QMR requests credit support and, in some cases fungible collateral, from companies with noninvestment-grade ratings. QMR's five largest nonaffiliated customers are BP Energy Company, Reliant Energy Services, Duke Energy Trading and Marketing, Sempra Energy Trading Corporation and Oneok Energy Marketing. Transactions with these five companies accounted for 14% of QMR's revenues.

FORWARD-LOOKING STATEMENTS

This report 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 report, 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;

Changes in gas and oil prices and supplies, and land-access issues;

Regulation of the Wexpro Agreement;

Availability of gas and oil properties for sale or for exploration;

Creditworthiness of counterparties to hedging contracts;

Rate of inflation and interest rates;

Assumptions used in business combinations;

Weather and other natural phenomena;

The effect of environmental regulation;

Competition from other energy sources;

The effect of accounting policies issued periodically by accounting standard-setting bodies;

Adverse repercussion from terrorist attacks or acts of war;

Adverse changes in the business or financial condition of the company; and

Lower credit ratings.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Financial Statements:

Report of Independent Auditors
Consolidated Statements of Income, three years ended December 31, 2002
Consolidated Balance Sheets at December 31, 2002 and 2001
Consolidated Statements of Common Shareholders' Equity, three years ended December 31, 2002
Consolidated Statement of Cash Flows, three years ended December 31, 2002
Notes to Consolidated Financial Statements
Financial Statement Schedules:
For the three years ended December 31, 2002
	Valuation and Qualifying Accounts

All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.

Report of Independent Auditors

Board of Directors
Questar Market Resources, Inc.

We have audited the accompanying consolidated balance sheets of Questar Market Resources, Inc. as of December 31, 2002 and 2001, and the related consolidated statements of income, shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and schedule 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 the 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. at December 31, 2002 and 2001, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

Ernst & Young LLP
Salt Lake City, UT
March 26, 2003

QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME

			Year Ended December 31,
			2002			2001			2000
			(in thousands)
REVENUES
	From unaffiliated customers		$	522,476		$	645,867		$	649,200
	From affiliates			106,647			100,530			92,853

		TOTAL REVENUES		629,123			746,397			742,053
OPERATING EXPENSES
	Cost of natural gas and other products sold			202,132			324,124			369,752
	Operating and maintenance			131,598			112,087			106,761
	Depreciation, depletion and amortization			117,446			92,678			85,025
	Exploration			6,086			6,986			7,917
	Abandonment and impairment of gas, oil and related properties			11,183			5,171			3,418
	Production and other taxes			28,558			43,125			36,262
	Wexpro Agreement—oil income sharing			1,676			2,885			4,758

		TOTAL OPERATING EXPENSES		498,679			587,056			613,893

		OPERATING INCOME		130,444			159,341			128,160
Interest and other income				50,894			17,259			8,750
Earnings from unconsolidated affiliates				3,977			1,265			2,776
Minority interest				484			359			(338	)
Debt expense				(34,705	)		(22,872	)		(22,922	)

		INCOME BEFORE INCOME TAXES		151,094			155,352			116,426
Income taxes				53,165			54,218			38,618

		NET INCOME	$	97,929		$	101,134		$	77,808

See notes to consolidated financial statements.

QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

				December 31,
				2002			2001
				(in thousands)
ASSETS
CURRENT ASSETS
	Cash and cash equivalents			$	10,404		$	2,270
	Notes receivable from Questar Corporation				95,600			9,500
	Accounts receivable, net				94,261			76,935
	Accounts receivable from affiliates				12,226			12,942
	Federal income taxes recoverable				8,426
	Fair value of hedging contracts				3,617			55,593
	Inventories, at lower of average cost or market
		Gas and oil storage			6,924			14,245
		Material and supplies			4,217			5,127
	Prepaid expenses and other				7,965			11,661

		TOTAL CURRENT ASSETS			235,214			196,699
PROPERTY, PLANT AND EQUIPMENT
	Gas and oil properties—successful efforts accounting
		Proved properties			1,103,686			1,175,432
		Unproved properties, not being amortized			131,817			176,141
		Support equipment and facilities			29,571			11,414
	Cost-of-service gas and oil operations—Successful efforts accounting				428,597			405,783
	Gathering, processing, marketing and other				223,974			210,394

					1,917,645			1,979,164
Less accumulated depreciation, depletion and amortization
	Gas and oil properties				424,392			462,143
	Cost-of-service gas and oil operations				224,440			207,410
	Gathering, processing, marketing and other				68,157			61,777

					716,989			731,330

		NET PROPERTY, PLANT AND EQUIPMENT			1,200,656			1,247,834
INVESTMENT IN UNCONSOLIDATED AFFILIATES					23,617			23,829
OTHER ASSETS
	Goodwill				61,423			66,823
	Other				2,787			3,279

					64,210			70,102

				$	1,523,697		$	1,538,464

LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES
	Notes payable to Questar			$	9,900		$	275,100
	Accounts payable and accrued expenses
		Accounts and other payables			91,443			91,657
		Accounts payable to affiliates			4,179			5,793
		Federal income taxes			14,315
		Production and other taxes			21,770			24,902
		Interest			9,119			4,805

			Total accounts payable and accrued expenses		140,826			127,157
	Fair value of hedging contracts				24,278			5,323
	Current portion of long-term debt							1,696

			TOTAL CURRENT LIABILITIES		175,004			409,276
LONG-TERM DEBT, less current portion					550,000			402,226
DEFERRED INCOME TAXES					204,185			175,024
OTHER LIABILITIES					19,013			17,140
MINORITY INTEREST					8,156			8,369
COMMITMENTS AND CONTINGENCIES
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
	Additional paid-in capital				116,027			116,027
	Retained earnings				463,883			383,254
	Accumulated other comprehensive income (loss)				(16,880	)		22,839

					567,339			526,429

				$	1,523,697		$	1,538,464

See notes to consolidated financial statements.

QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY

		Common Stock		Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (loss)			Comprehensive Income
		(in thousands)
Balance at January 1, 2000		$	4,309	$	116,027	$	238,912		$	(2,743	)
	2000 net income						77,808					$	77,808
	Cash dividends						(17,300	)
	Other comprehensive income:
	Unrealized gain on securities available for sale, net of income taxes of $1,557									2,515			2,515
	Foreign currency translation adjustment, net of income taxes of $949									(1,017	)		(1,017	)

Balance at December 31, 2000			4,309		116,027		299,420			(1,245	)	$	79,306

	2001 net income						101,134					$	101,134
	Cash dividends						(17,300	)
	Other comprehensive income:
	Cumulative effect of accounting change for energy hedges, net income taxes of $41,624									(79,376	)		(79,376	)
	Unrealized gain on energy hedges, net of income taxes of $57,048									105,295			105,295
	Unrealized loss on interest-rate swaps, net of income taxes of $235									(392	)		(392	)
	Foreign currency translation adjustment, net of income taxes of $1,304									(1,443	)		(1,443	)

Balance at December 31, 2001			4,309		116,027		383,254			22,839		$	125,218

	2002 net income						97,929					$	97,929
	Cash dividends						(17,300	)
	Other comprehensive income:
	Change in unrealized loss on energy hedges, net of income taxes of $25,651									(42,799	)		(42,799	)
	Change in interest-rate swaps, net of income taxes of $235									392			392
	Foreign currency translation adjustment, net of income taxes of $2,375									2,688			2,688

Balance at December 31, 2002		$	4,309	$	116,027	$	463,883		$	(16,880	)	$	58,210

See notes to consolidated financial statements.

QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

			Year Ended December 31,
			2002			2001			2000
			(in thousands)
OPERATING ACTIVITIES
Net income			$	97,929		$	101,134		$	77,808
	Adjustments to reconcile net income to net cash provided from operating activities
		Depreciation, depletion and amortization		122,657			94,776			85,733
		Deferred income taxes		53,684			34,594			22,818
		Abandonment and impairment of gas, oil and related properties		11,183			5,171			3,418
		(Earnings) loss from unconsolidated affiliates, net of cash distributions		2,757			(1,071	)		(2,117	)
		Net gain from sales of properties and securities		(43,240	)		(13,898	)		(1,731	)
	Changes in operating assets and liabilities
		Accounts receivable and qualifying hedging collateral		(22,498	)		113,072			(112,757	)
		Inventories		8,339			(8,099	)		1,337
		Energy-hedging contracts		(89	)		(10,886	)
		Prepaid expenses and other		2,187			(4,012	)		(423	)
		Accounts payable and accrued expenses		2,991			(53,981	)		73,103
		Federal income taxes		22,771			(3,459	)		(11,207	)
		Other assets		(755	)		1,031			(3,125	)
		Other liabilities		3,578			(3,074	)		(1,608	)

NET CASH PROVIDED FROM OPERATING ACTIVITIES				261,494			251,298			131,249
INVESTING ACTIVITIES
Capital expenditures
	Purchase of property, plant and equipment			(171,475	)		(630,807	)		(187,359	)
	Other investments			(17,885	)		(7,700	)

				(189,360	)		(638,507	)		(187,359	)
Proceeds from disposition of assets				157,979			32,729			20,678

NET CASH USED IN INVESTING ACTIVITIES				(31,381	)		(605,778	)		(166,681	)
FINANCING ACTIVITIES
Change in notes receivable from Questar				(86,100	)		(9,500	)		4,000
Change in notes payable to Questar				(265,200	)		224,100			26,500
Change in short-term debt							(12,500	)		12,500
Change in cash in escrow							5,387			31,340
Checks written in excess of cash balances										(1,246	)
Issuance of long-term debt				325,000			405,000			61,725
Payment of long-term debt				(179,104	)		(242,837	)		(80,087	)
Other financing				723			646			2,955
Payment of dividends				(17,300	)		(17,300	)		(17,300	)

NET CASH PROVIDED FROM (USED IN) FINANCING ACTIVITIES				(221,981	)		352,996			40,387
	Foreign currency translation adjustments			2			(226	)		(975	)

Change in cash and cash equivalents				8,134			(1,710	)		3,980
Beginning cash and cash equivalents				2,270			3,980

ENDING CASH AND CASH EQUIVALENTS			$	10,404		$	2,270		$	3,980

See notes to consolidated financial statements.

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 (Questar E & P) and its subsidiary, Shenandoah Energy Inc. (SEI), conduct exploration, development and production activities. Wexpro Company (Wexpro) operates and develops producing properties owned by an affiliate, Questar Gas. Questar Gas Management gathers and processes natural gas. Questar Energy Trading performs wholesale energy marketing activities and through its interest in Clear Creek Storage Company, LLC, operates a private gas-storage field. All significant intercompany balances and transactions have been eliminated in consolidation.

Investments in Unconsolidated Affiliates: QMR uses the equity method to account for investment in affiliates in which it does not have control. Generally, QMR's investment in these affiliates equals the underlying equity in net assets.

Use of Estimates: The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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: The company's exploration and production operations use the sales method of accounting for gas revenues, whereby revenue is recognized on all gas sold to purchasers. A liability is recorded to the extent that the company has sold gas in excess of its share of remaining reserves in an underlying property. The company's net gas imbalances at December 31, 2002 and 2001 were $1.8 million and $1.9 million, respectively. Revenue and prices for gas and oil are reported "net to the well," meaning that costs for gathering and processing, often times paid by purchasers of the products, are not included in the revenues reported.

Wexpro Agreement—Oil Income Sharing: Wexpro agreement-oil income sharing represents payments made to Questar Gas for its share of the income from oil and NGL products associated with cost-of-service oil properties pursuant to the terms of the Wexpro Agreement (Note 10).

Regulation of Underground Storage: Clear Creek Storage Company, LLC operates an underground gas storage facility that is under the jurisdiction of the Federal Energy Regulatory Commission (FERC). The FERC establishes rates for the storage of natural gas, and regulates the extension and enlargement or abandonment of jurisdictional natural gas facilities. Regulation is intended to permit the recovery, through rates, of the cost of service, including a return on investment.

Cash and Cash Equivalents: Cash equivalents consist principally of repurchase agreements with maturities of three months or less. In almost all cases, the repurchase agreements are highly liquid investments in overnight securities made through the company's commercial bank accounts that result in available funds the next business day.

Notes Receivable from Questar: Notes receivable from Questar represent interest bearing demand notes for cash 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: Property, plant and equipment is stated at cost. In 2001, Questar elected to change its accounting method for gas and oil properties from the full-cost method to the successful-efforts method. The company retroactively restated financial statements to reflect this change in accounting method.

Gas and oil properties

Under the successful-efforts method of accounting, the company capitalizes the costs of acquiring leaseholds, drilling development wells, drilling successful exploratory wells, and purchasing related support equipment and facilities. The costs of unsuccessful exploratory wells are charged to expense when it is determined that such wells have not located proved reserves. Unproved-leasehold costs are periodically reviewed for impairment. Costs related to impaired prospects are charged to expense. Costs of geological and geophysical studies and other exploratory activities are expensed as incurred. Costs associated with production and general corporate activities are expensed in the period incurred. The company recognizes gain or loss on the sale of properties on a field basis.

Capitalized-proved-leasehold costs are depleted using the unit-of-production method based on proved reserves on a field basis. All other capitalized costs associated with gas and oil properties are depreciated using the unit-of-production method based on proved-developed reserves on a field basis. Costs of future site restoration, dismantlement, and abandonment of producing properties are considered in calculating depreciation, depletion and amortization expense for tangible equipment by assuming no salvage value in the calculation of the unit-of-production rate.

Cost-of-service gas and oil operations

The successful-efforts method of accounting is utilized with respect to costs associated with certain "cost-of-service" gas and oil properties managed and developed by Wexpro. Cost-of-service gas and oil properties are properties for which the operations and return on investment are regulated by the Wexpro Agreement (see Note 10). In accordance with the 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. Oil produced from the cost-of-service properties is sold at market prices. Proceeds are credited pursuant to the terms of the agreement, allowing Questar Gas to share in the proceeds for the purpose of reducing natural gas rates.

Capitalized costs are depreciated on an individual-field basis using the unit-of-production method based upon proved-developed gas and oil reserves attributable to the field. Costs of future site restoration, dismantlement, and abandonment for producing properties are considered in calculating depreciation and amortization expense for tangible equipment by assuming no salvage value in the calculation of the unit-of-production rate.

Depreciation for gathering and processing facilities is determined using either the straight-line or unit-of-production methods. The estimated useful lives for straight-line purposes ranges from 3 to 20 years.

Average depreciation, depletion and amortization rates used in the year ended December 31 were as follows:

			2002		2001		2000
Gas and oil properties, per Mcf equivalent
	U.S.		$	.90	$	.79	$	.73
	Canada (in U.S. dollars)			.98		1.10		1.12
		Combined U.S. and Canada		.91		.83		.78
Cost-of-service gas and oil properties, per Mcfe				.59		.49		.44

Test for Impairment of Long-Lived Assets: Gas and oil properties are evaluated by field for potential impairment; other properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable in accordance with Statement of Financial Accounting Standards (SFAS) 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." An impairment is indicated when a triggering event occurs and the estimated undiscounted future net cash flows of an evaluated asset are less than its carrying value. Triggering events that may result in a decrease of gas and oil reserves could be caused by mechanical problems, a faster decline of reserves than expected, lease-ownership issues, and/or an other-than-temporary decline in gas and oil prices. If an impairment is indicated, fair value is calculated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors including pricing and operating costs.

Goodwill and Other Intangible Assets: Intangible assets consist primarily of goodwill acquired through business combinations. The excess of the cost over the fair value of net assets of acquired businesses is recorded as goodwill. On January 1, 2002, the company adopted SFAS 142, "Goodwill and Other Intangible Assets." According to SFAS 142, goodwill is no longer amortized, but is tested for impairment at a minimum of once a year or when an event occurs. When a triggering event occurs, the undiscounted net cash flows of the asset or entity to which the goodwill relates are evaluated. If undiscounted cash flows are less than the carrying value of the assets, an impairment is indicated. The amount of the impairment is measured using a discounted-cash-flow model considering pricing, operating costs, a risk-adjusted discount rate and other factors. QMR acquired $66.8 million as a result of acquiring SEI in July of 2001. In 2002, the sale of the Canadian subsidiary resulted in a $5.4 million decrease in goodwill.

Capitalized Interest and Allowance for Funds Used During Construction: When applicable, QMR capitalizes interest costs during the construction period of plant and equipment. However, the company did not capitalize interest costs in 2002, 2001 and 2000. Under provisions of the Wexpro Agreement, the company capitalizes an allowance for funds used during construction (AFUDC) on cost-of-service construction projects. The FERC requires the capitalization of AFUDC during the construction period of rate-regulated plant and equipment. AFUDC amounted to $444,000 in 2002, $703,000 in 2001 and $2.2 million in 2000, and is included in Interest and Other Income in the Consolidated Statements of Income.

Foreign-Currency Translation: The company conducted gas and oil development-and-production operations in Canada, which were sold in 2002. The local currency, the Canadian dollar, was the functional currency of the company's foreign operations. Translation from Canadian dollars to U. S. dollars was performed for balance-sheet accounts using the exchange rate in effect at the balance-sheet date. Revenue and expense accounts were translated using an average exchange rate. Adjustments resulting from such translations were reported as a separate component of other comprehensive income in shareholders' equity. Deferred income taxes were provided on translation adjustments because the earnings were not considered to be permanently invested.

Energy-Price Financial Instruments: On January 1, 2001, the company adopted the accounting provisions of SFAS 133 as amended and recorded a cumulative effect of this accounting change that decreased other comprehensive income by $79.4 million after tax. The company structures the majority of its energy-price-derivative instruments as cash-flow hedges.

The company may elect to designate a derivative instrument as a hedge of exposure to changes in fair value, cash flows or foreign currencies. If the hedged exposure is a fair-value exposure, the gain or loss on the derivative instrument is recognized in earnings in the period of the change together with the offsetting gain or loss from the change in fair value of the hedged item. If the hedged exposure is a cash-flow exposure, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any amount excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the gain or loss, is reported in earnings in the current period.

A derivative instrument qualifies as a hedge if all of the following tests are met:

•: The item to be hedged exposes the company to price risk.
•: The derivative reduces the risk exposure and is designated as a hedge at the time the company enters into the contract.
•: At the inception of the hedge and throughout the hedge period there is a high correlation between changes in the market value of the derivative instrument and the fair value of the underlying item being hedged.

When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are included in income in the same period that the underlying production or other contractual commitment is delivered. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if correlation no longer exists, the gain or loss on the derivative is reclassified from other comprehensive income and recognized currently in the results of operations.

Physical Contracts: Physical hedge contracts have a nominal quantity and a fixed price. Contracts representing both purchases and sales settle monthly based on quantities valued at a fixed price. Purchase contracts fix the purchase price paid and are recorded as cost of sales in the month the contracts are settled. Sales contracts fix the sales price received and are recorded as revenues in the month they are settled. Due to the nature of the physical market, there is a one-month delay for the actual settlement. QMR accrues for the settlement in the current month's revenues and cost of sales.

Financial Contracts: Financial contracts are contracts which are net settled; meaning settled in cash without delivery of product. Financial contracts also have a nominal quantity and exchange an index price for a fixed price. They are net settled with the brokers as the price bulletins become available. The contracts are recorded as cost of sales in the month they are settled.

Interest-Rate Financial Instruments: The company may utilize interest-rate hedges to swap fixed-rate interest payments for variable-rate interest payments. The difference between the fixed-interest-rate-swap payment made and the variable-rate payment is recorded as either an increase or decrease of interest expense.

Credit Risk: The company's primary market areas are the Rocky Mountain and Midcontinent 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 individuals and numerous industries that may be affected differently by changing conditions. Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures 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. Loss reserves are periodically reviewed for adequacy and may be established on a specific-case basis. Bad-debt expense amounted to $1.2 million, $1.2 million and $431,000 for the years ended December 31, 2002, 2001 and 2000, respectively. The allowance for bad-debt expenses was $3.8 million and $2.8 million at December 31, 2002 and 2001, respectively.

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 reporting purposes. The company receives payments from Questar for such tax benefits as they are utilized on the consolidated return. QMR records tax benefits as they are generated. Deferred income taxes have been provided for temporary difference caused by the differences between the book and tax carrying amounts of assets and liabilities. These differences create taxable or tax deductible amounts for future periods.

Comprehensive Income: Comprehensive income is the sum of net income as reported in the Consolidated

Statements of Income and other comprehensive income transactions reported in the Consolidated Statements of Shareholder's Equity. Other comprehensive income transactions reported by QMR result from changes in fair value of qualified energy derivatives, interest rate derivatives 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. Income or loss is realized when the underlying products or securities available for sale are sold.

The balances of cumulative other comprehensive income (loss), net of income taxes at December 31, were as follows:

	2002			2001
	(in thousands)
Unrealized gain (loss) on energy hedging transactions	($	16,880	)	$	25,919
Unrealized loss on interest rate swap					(392	)
Foreign currency translation adjustment					(2,688	)

Accumulated other comprehensive income (loss)	($	16,880	)	$	22,839

Business Segments: QMR's line-of-business disclosures are presented based on the way senior management evaluates the performance of its business segments. Certain intersegment sales include intercompany profit.

New Accounting Standard: SFAS 143, "Accounting for Asset Retirement Obligations," was issued in June of 2001. SFAS 143 addresses the financial accounting and reporting of the fair value of legal obligations associated with the retirement of tangible long-lived assets. The new standard requires that plant abandonment costs be estimated at fair value, capitalized and depreciated over the life of the related assets. The new standard will have its greatest impact on recording abandonment costs of gas and oil wells, and to a lesser extent, on processing plants. The company has not completed its evaluation of the impact of SFAS 143. However, these expenses are noncash until abandonment takes place. SFAS 143 is effective beginning January 1, 2003.

Reclassifications: Certain reclassifications were made to the 2001 and 2000 financial statements to conform with the 2002 presentation.

Note 2—Dispositions and Acquisitions

Sale of Canadian Properties

On October 21, 2002, QMR sold its Canadian exploration and production subsidiary, Celsius Energy Resources, Ltd (CERL), to EnerMark Inc., a subsidiary of Calgary-based Enerplus Resources Fund. Total consideration received was $US 101.6 million. CERL earned net income for the nine months ended September 30, 2002, of $US 1.5 million and had total assets of $US 80 million at September 30, 2002. QMR used the proceeds from the sale to repay debt.

Partnership Interest Acquired

QMR, through an affiliate, acquired El Paso Gas Gathering and Processing's 50% interest in the Blacks Fork processing plant for approximately $5.4 million, effective December 18, 2002. QMR now owns 100% of the plant. Accounting for the company's interest in Blacks Fork changed from an unconsolidated partnership to full consolidation as a result of this transaction.

Note 3—Investment in Unconsolidated Affiliates

QMR, indirectly through subsidiaries, has interests in partnerships accounted for on an equity basis. These entities are engaged primarily in gathering and/or processing natural gas. These affiliates did not have debt obligations with third-party lenders. The percentage of voting control and economic interest are identical. The principal partnerships are Canyon Creek Compression Co. (15%), a general partnership, and Rendezvous Gas Services LLC (50%), a limited liability corporation.

Summarized results of the partnerships are listed below.

	2002		2001		2000
	(in thousands)
Year Ended December 31,
Revenues	$	25,490	$	24,992	$	27,574
Operating income		8,805		2,830		5,811
Income before income taxes		8,869		3,105		6,184
At December 31,
Current assets	$	11,806	$	21,000	$	14,232
Noncurrent assets		45,704		38,862		26,941
Current liabilities		5,178		3,893		3,940
Noncurrent liabilities		2,182		2,529		946

Note 4—Debt

Questar makes loans to QMR under a short-term borrowing arrangement. Short-term notes payable to Questar totaled $9.9 million at December 31, 2002 with an interest rate of 1.64% and $275.1 million at December 31, 2001 with an interest rate of 2.31%.

	December 31,
	2002		2001
	(in thousands)
Long-term debt
Revolving-credit loan due 2004 with variable interest rates (2.21% at December 31, 2002)	$	200,000	$	253,922
7.0% Notes due 2007		200,000
7.5% Notes due 2011		150,000		150,000

		550,000		403,922
Less current portion		1,696

	$	550,000	$	402,226

Maturities of long-term debt for the five years following December 31, 2002, are as follows:

	in thousands
2003		—
2004	$	180,000
2005		20,000
2006		—
2007		200,000

QMR's revolving credit facility contains covenants specifying a minimum amount of net equity and a maximum ratio of debt to equity. The most restrictive terms of the revolving credit facility limit payment of dividends to $143 million.

Cash paid for interest was $30 million in 2002, $22.9 million in 2001 and $23.4 million in 2000.

Note 5—Financial Instruments and Risk Management

The carrying amounts and estimated fair values of the company's financial instruments were as follows:

		December 31, 2002				December 31, 2001
		Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
		(in thousands)
Financial assets
	Cash and cash equivalents	$	10,404	$	10,404	$	2,270	$	2,270
	Notes receivable		95,600		95,600		9,500		9,500
	Energy-price hedging contracts		3,617		3,617		55,593		55,593
Financial liabilities
	Short-term debt		9,900		9,900		275,100		275,100
	Long-term debt		550,000		585,087		402,226		401,590
	Energy-price hedging contracts		24,278		24,278		4,696		4,696
	Interest-rate swap		—		—		627		627

The company used the following methods and assumptions in estimating fair values: Cash and cash equivalents and short-term debt—the carrying amount approximates fair value. Long-term debt—the carrying amount of variable-rate debt approximates fair value. The fair value of fixed-rate debt is based on the discounted present value of cash flows using the company's current borrowing rates.

Energy-price-hedging contracts—fair value of the contracts is based on market prices as posted on the NYMEX from the last trading day of the year. The average price of the gas contracts at

December 31, 2002, was $3.42 per MMBtu, representing the average of contracts with different terms including fixed, various "into-the-pipe" postings and NYMEX references. Energy-price-hedging contracts were in place for equity gas production and gas-marketing transactions. Deducting transportation and heat-value adjustments on the hedges of equity gas as of December 31, 2002, would result in a price of approximately $3.19 per Mcf, net-to-the-well. The average price of the oil contracts at December 31, 2002, was $23.15 per bbl and was based on the average of fixed amounts in contracts which settle against the NYMEX. All oil contracts relate to equity production where basis adjustments would result in a net-to-the-well price of $21.80 per bbl.

QMR held energy-price-hedging contracts covering the price exposure for about 85.2 million dth of gas and 1.1 MMbl of oil as of December 31, 2002. A year earlier QMR hedging contracts covered 70.2 MMdth of natural gas and 1.1 MMbl of oil. QMR does not hedge the price of natural gas liquids.

At December 31, 2002, the company reported a net $20.7 million current liability from hedging activities net of hedging assets. Settlement of contracts in 2002 resulted in the reclassification into income of $42.4 million ($26.2 million after tax). The offset to the hedging liability, net of income taxes, was a $42.8 million unrealized loss on hedging activities recorded in other comprehensive income in the shareholder's equity section of the balance sheet. The ineffective portion of hedging transactions recognized in earnings was not significant. The fair-value calculation of energy-price hedges does not consider changes in the fair value of the corresponding scheduled equity physical transactions, (i.e., the correlation between index price and the price realized for the physical delivery of gas or oil.)

Interest-rate swap—the mark-to-market valuation equals a discounted present value of future cash flow using current market rates. In October 2001, the company hedged $100 million of variable-rate debt by entering into a fixed-rate interest swap. The swap expired October 2002 and was not renewed.

Note 6—Income Taxes

The components of income taxes for years ended December 31 were as follows:

		2002			2001		2000
		(in thousands)
Federal
	Current	$	(1,742	)	$	19,962	$	13,678
	Deferred		39,839			24,528		19,947
State
	Current		(2,902	)		1,022		1,129
	Deferred		12,302			2,837		1,763
Foreign			5,668			5,869		2,101

		$	53,165		$	54,218	$	38,618

The difference between the statutory federal income tax rate and QMR's effective income tax rate is explained as follows:

	2002		2001		2000
	(in percentages)
Statutory federal income tax rate	35.0		35.0		35.0
Increase (decrease) as a result of:
State income tax rate, net of federal
income tax credit	4.0		1.6		1.6
Nonconventional fuel credits	(3.3	)	(3.3	)	(4.0	)
Foreign income taxes	(.1	)	1.7		0.6
Goodwill	1.0
Other	(1.4	)	(0.1	)

Effective income tax rate	35.2		34.9		33.2

Significant components of the company's deferred income taxes at December 31 were as follows:

			2002		2001
			(in thousands)
Deferred tax liabilities
	Property, plant and equipment		$	239,640	$	195,227
Deferred tax assets
	Mark to market hedging activities			11,498		15,946
	Tax attributes carried forward			20,520
	Employee benefits and compensation costs			3,437		4,257

				35,455		20,203

		Net deferred income taxes	$	204,185	$	175,024

In 2002, QMR received an income tax refund amounting to $32 million. Cash paid for income taxes amounted to $22.3 million in 2001 and $25.6 million in 2000. Tax attributes consist of net operating losses carried forward, nonconventional fuel credits and alternative minimum tax credits.

Note 7—Litigation and Commitments

Grynberg: Questar defendants are involved in three separate lawsuits filed by Jack Grynberg, an independent producer. One case involves claims filed by Grynberg under the federal False Claims Act and is substantially similar to other cases filed against pipelines and their affiliates that have all been consolidated for discovery and pre-trial motions in Wyoming's federal district court. The cases involve allegations of industrywide mismeasurement of natural gas volumes on which royalty payments are due the federal government. Grynberg has filed an appeal from the order issued by the trial judge dismissing his valuation claims from the lawsuits. To sustain claims under the False Claims Act, Grynberg must demonstrate that he is the original source of information concerning the allegations and that he has "direct and independent knowledge" of the claimed mismeasurement practices. The Questar defendants participate in a joint defense group that is challenging Grynberg's eligibility to bring such claims.

On March 21, 2003, the Utah Supreme Court substantially upheld the trial court's order granting summary judgment to the Questar defendants in this case. The case involves claims that several Questar entities mismeasured the heating content of gas volumes attributable to Grynberg's working interest in specified wells in southwestern Wyoming, committed fraud, and breached fiduciary responsibilities. Specifically, the court ruled Grynberg's contract claims were time-barred, the economic

loss doctrine precludes him from bringing tort claims based on contractual responsibilities, he is not a third party beneficiary of his operator's contracts, Questar defendants do not owe him fiduciary responsibilities, and there was no equitable tolling of the applicable statutes of limitations. The court also ruled that Grynberg was not collaterally estopped from presenting a contract termination issue that had been previously ruled on by a Wyoming federal district court judge and remanded the case to the trial court to determine whether any contractual claims remain.

The third case is pending in a Wyoming federal district court against Questar Gas, as the successor to Questar Pipeline's interest in gas-purchase contracts. This case involves some of the same allegations that were heard in an earlier case between the parties, e.g., breach of contract, intentional interference with a contract, but Grynberg added claims of antitrust and fraud. In June of 2001, the judge entered an order granting the motion for partial summary judgment filed by Questar Gas dismissing the antitrust claims from the case, but has not ruled on other motions for summary judgment dealing with ratable take and fraud.

Gas Pipelines. Questar E & P, Questar Gas Management, Wexpro and affiliates, Questar Gas, and Questar Pipeline are among the numerous defendants in a case filed against the pipeline industry. Pending in a Kansas state district court, this case is similar to the cases filed by Grynberg, but the allegations of a conspiracy by the pipeline industry to set standards that result in the systematic mismeasurement of natural gas volumes and resulting underpayment of royalties are made on behalf of private and state lessors rather than on behalf of the federal government. The numerous defendants are opposing class certification and are requesting dismissal for lack of personal jurisdiction of any defendants, including most of the named Questar parties, that do not conduct business activities in Kansas.

Environmental Compliance. An Oklahoma agency has advised Questar Gas Management that it may be violating state-air pollution laws in conjunction with its operation of processing facilities in the state by failing to obtain necessary permits, submit proper notices, and pay specified emissions fees.

Other legal proceedings

There are various other legal proceedings against QMR and its subsidiaries. While it is not currently possible to predict or determine the outcomes of these proceedings, it is the opinion of management that the outcomes will not have a materially adverse effect on the company's results of operations, financial position or liquidity.

Commitments

Questar Energy Trading has contracted for firm-transportation services with various pipelines through 2016. Due to market conditions and competition, it is possible that Questar Energy Trading may not be able to recover the full cost of these transportation commitments. Annual payments and the years covered are as follows:

	(in thousands)
2003	$	3,174
2004		1,048
2005		1,042
2006		1,032
2007		974
2008		358
Yearly commitment fee 2009 through 2016		194

QMR rents office space throughout its scope of operations from third-party lessors and leases space in an office building located in Salt Lake City, Utah from an affiliated company. 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, 2002, are as follows:

	(in thousands)
2003	$	1,986
2004		1,801
2005		1,756
2006		1,710
2007		1,321

Minimum future rental payments have not been reduced for sublease rental receipts of $103,000 in 2003 and $9,000 in 2004. Total rental expense amounted to $2.4 million in 2002, $2.2 million in 2001 and $2.1 million in 2000. Sublease rental receipts were $70,000 in 2002, $294,000 in 2001 and $118,000 in 2000.

Note 8—Employee Benefits

Pension Plan: A majority of QMR's employees are covered by Questar's defined benefit pension plan. Benefits are generally based on the employee's age at retirement, years of service and highest earnings in a consecutive 72 pay-period interval during the ten years preceding retirement. The company's policy is to make contributions to the plan at least sufficient to meet the minimum funding requirements of the Internal Revenue Code. Plan assets consist principally of equity securities and corporate and U.S. government debt obligations. The company relies on a third-party consultant to calculate the pension plan projected benefit obligation. Pension expense was $855,000 in 2002, $955,000 in 2001 and $385,000 in 2000.

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, 2002, Questar's accumulated benefit obligation exceeded the fair value of plan assets.

Postretirement Benefits Other Than Pensions: Postretirement health-care benefits and life insurance are provided only to employees hired before January 1, 1997. The company pays a portion of the costs of health-care benefits, as determined by an employee's years of service, and limited to 170% of the 1992 contribution. 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 its transition obligation over a 20-year period, which began in 1992. The company relies on a third-party consultant to calculate the projected benefit obligation. The cost of postretirement benefits other than pensions was $1.3 million in 2002, $1.3 million in 2001 and $1.7 million in 2000.

The company'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. At December 31, 2002, Questar's accumulated benefit obligation exceeded the fair value of plan assets.

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. QMR's postemployment liability at December 31 was $689,000 in 2002 and $539,000 in 2001.

Employee Investment Plan: QMR participates in Questar's Employee Investment Plan (Plan), which allows eligible employees to purchase shares of Questar Corporation common stock or other investments through payroll deduction. The company matches 80% of employees' pretax purchases up to a maximum of 6% of their qualifying earnings. In addition, each year the company makes a nonmatching contribution of $200 to each eligible employee. The company's expense equals its matching contribution. The company's expense amounted to $1.4 million, $1.3 million and $1.1 million for the years ended December 31, 2002, 2001 and 2000.

Note 9—Related Party Transactions

QMR receives a significant portion of its revenues from services provided to Questar Gas Company. The company received $106.6 million in 2002, $100.5 million in 2001 and $92.5 million in 2000 for operating cost-of-service gas properties, gathering gas and supplying a portion of gas for resale, among other services provided to Questar Gas. Operation of cost-of-service gas properties is described in Wexpro Agreement (Note 10). QMR also received revenues from other affiliated companies totaling $.4 million in 2000. In 2002 and 2001, revenues from Questar Gas accounted for all of QMR's intercompany transactions.

Questar performs certain administrative functions for QMR and charged $9.1 million in 2002, $7.8 million in 2001, and $6.6 million in 2000. QMR includes these costs in operating and maintenance expenses. Questar allocates the costs based on each affiliate proportional share of revenues, net of gas costs; property, plant and equipment; and payroll. Management believes that the allocation method is reasonable.

QMR's subsidiaries contracted for transportation and storage services with Questar Pipeline and paid $1.3 million in 2002 and 2001 and $2.1 million in 2000 for these services. Questar InfoComm is an affiliated company that provides some information technology and communication services to Questar and its affiliated companies. QMR paid Questar InfoComm $1.4 million in 2002 and 2001, and $1.9 million in 2000.

QMR has a 5-year lease with Questar for space in an office building located in Salt Lake City, Utah. The building is owned by a third party. The third party has a lease arrangement with Questar Corp, which in turn sublets office space to affiliated companies. The lease between QMR and Questar expires October 2007. The lease payment for 2003 is $761,000. QMR paid $938,000 in 2002 and $945,000 in 2001 and 2000 on this lease.

The company received interest income from affiliated companies of $.7 million in 2002, and $.6 million in 2001 and 2000. QMR incurred debt expense to affiliated companies of $2.8 million in 2002, $3.1 million in 2001 and $2.5 million in 2000.

Note 10—Wexpro Agreement

Wexpro's operations are subject to the terms of the Wexpro Agreement. The agreement was effective August 1, 1981, and sets forth the rights of Questar Gas's 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 agreement are as follows:

a. Wexpro continues to hold and operate all oil-producing properties previously transferred from Questar Gas's 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 13.6%. 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 properties 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 18.6%. 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 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 21.6%.

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 13.6%.

Wexpro's investment base, net of deferred income taxes, and the yearly average rate of return for 2002 and the previous two years is shown in the table below:

	2002			2001			2000
Wexpro investment base, net
of deferred income taxes (in millions)	$	164.5		$	161.3		$	124.8
Annual average rate of return (after tax)		20.5	%		19.7	%		19.5	%

Note 11—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 operations and management objectives. The reportable segments are managed separately because each segment requires different operational assets, technology and management strategies. All goodwill is attributable to the exploration and production segment.

		Year Ended December 31,
		2002		2001		2000
		(in thousands)
Revenues from Unaffiliated Customers
	Exploration and production	$	270,843	$	280,576	$	245,728
	Cost of service		8,699		12,465		15,179
	Gathering, processing and marketing		242,934		352,826		388,293

			522,476		645,867		649,200

Revenues from Affiliated Companies
	Exploration and production		1,172		807		18
	Cost of service		94,827		88,936		73,721
	Gathering, processing and marketing		10,648		10,787		19,114

			106,647		100,530		92,853

Depreciation, Depletion and Amortization Expense
	Exploration and production		88,888		70,601		65,169
	Cost of service		20,475		15,051		13,922
	Gathering, processing and marketing		8,083		7,026		5,934

			117,446		92,678		85,025

Operating Income
	Exploration and production		64,404		101,531		77,919
	Cost of service		52,124		45,030		38,502
	Gathering, processing and marketing		13,916		12,780		11,739

			130,444		159,341		128,160

Interest and Other Income
	Exploration and production		47,221		14,265		387
	Cost of service		555		847		472
	Gathering, processing and marketing		3,118		2,147		7,912

			50,894		17,259		8,750

			Year Ended December 31,
			2002		2001		2000
			(in thousands)
Debt Expense
	Exploration and production			26,167		18,202		17,976
	Cost of service			4,570		1,789		721
	Gathering, processing and marketing			3,968		2,881		4,225

				34,705		22,872		22,922

Income Taxes
	Exploration and production			29,316		33,355		18,483
	Cost of service			17,318		15,847		13,873
	Gathering, processing and marketing			6,531		5,016		6,262

				53,165		54,218		38,618

Net income
	Exploration and production			56,182		64,452		42,137
	Cost of service			30,791		28,241		24,380
	Gathering, processing and marketing			10,956		8,441		11,291

				97,929		101,134		77,808

Fixed Assets—Net
	Exploration and production			840,682		900,844		502,766
	Cost of service			204,157		198,373		155,374
	Gathering, processing and marketing			155,817		148,617		79,096

				1,200,656		1,247,834		737,236

Capital Expenditures
	Exploration and production			131,200		549,096		140,487
	Cost of service			26,661		58,453		32,048
	Gathering, processing and marketing			31,499		30,958		14,824

				189,360		638,507		187,359

GEOGRAPHIC INFORMATION
	Revenues
		United States		607,429		707,902		703,981
		Canada		21,694		38,495		38,072

				629,123		746,397		742,053

	Fixed Assets—Net
		United States		1,200,656		1,171,697		648,089
		Canada		76,137		89,147

			$	1,200,656	$	1,247,834	$	737,236

Note 12—Supplemental Gas and Oil Information (Unaudited)

The company uses the successful efforts accounting method for its gas and oil exploration and development activities and for certain cost-of-service gas and oil properties managed and developed by Wexpro.

Gas and Oil Exploration and Development Activities: The following information is provided with respect to Questar's gas and oil exploration and development activities, which are located in the United States since the sale of Canadian properties in the fourth quarter of 2002.

Capitalized Costs

The aggregate amounts of costs capitalized for gas and oil exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization follow as of December 31:

				2001
		2002 United States		2001
		2002 United States		United States		Canada		Total
		(in thousands)		(in thousands)
Proved properties		$	1,103,686	$	1,051,875	$	123,557	$	1,175,432
	Unproved properties		131,817		165,066		11,075		176,141
	Support equipment and facilities		29,571		11,017		397		11,414

			1,265,074		1,227,958		135,029		1,362,987
	Accumulated depreciation, depletion and amortization		424,392		403,251		58,892		462,143

		$	840,682	$	824,707	$	76,137	$	900,844

		2000
		United States		Canada		Total
				(in thousands)
Proved properties		$	732,078	$	113,407	$	845,485
	Unproved properties		30,940		24,668		55,608
	Support equipment and facilities		12,002		1,177		13,179

			775,020		139,252		914,272
	Accumulated depreciation, depletion and amortization		361,401		50,105		411,506

		$	413,619	$	89,147	$	502,766

Costs Incurred

The costs incurred in gas and oil exploration and development activities are displayed in the table below. The costs incurred to develop booked proved-undeveloped reserves amounted to $51.1 million, $20.7 million and $7.1 million in 2002, 2001 and 2000, respectively.

Year Ended December 31,		United States		Canada		Total
		(in thousands)
2002
Property acquisition
	Unproved	$	1,092	$	119	$	1,211
	Proved		45				45
Exploration			10,372		627		10,999
Development			121,763		3,268		125,031

		$	133,272	$	4,014	$	137,286

2001
Property acquisition
	Unproved	$	1,309	$	318	$	1,627
	Proved		303,757				303,757
Exploration			14,063		1,755		15,818
Development			130,638		5,256		135,894

		$	449,767	$	7,329	$	457,096

2000
Property acquisition
	Unproved	$	3,054	$	14,703	$	17,757
	Proved		1,202		31,058		32,260
Exploration			6,433		3,664		10,097
Development			64,582		29,478		94,060

		$	75,271	$	78,903	$	154,174

Results of Operations

Following are the results of operations of Market Resources' gas and oil exploration and development activities, before corporate overhead and interest expenses.

				United States		Canada		Total
				(in thousands)
Year Ended December 31, 2002
Revenues
	From unaffiliated customers			$	249,239	$	21,694	$	270,933
	From affiliates				1,172				1,172

		Total revenues			250,411		21,694		272,105

Production expenses					62,625		6,924		69,549
Exploration					5,459		627		6,086
Depreciation, depletion and amortization					81,473		7,415		88,888
Abandonment and impairment of gas, oil and related properties					11,030		153		11,183

			Total expenses		160,587		15,119		175,706

Revenues less expenses					89,824		6,575		96,399
Income taxes—Note A					27,247		4,228		31,475

Results of operations before corporate overhead and interest expenses				$	62,577	$	2,347	$	64,924

				United States		Canada		Total
				(in thousands)
Year Ended December 31, 2001
Revenues
	From unaffiliated customers			$	242,081	$	38,495	$	280,576
	From affiliates				807				807

		Total revenues			242,888		38,495		281,383

Production expenses					62,646		8,106		70,752
Exploration					5,236		1,785		7,021
Depreciation, depletion and amortization					58,537		12,064		70,601
Abandonment and impairment of gas and oil properties					3,571		1,600		5,171

			Total expenses		129,990		23,555		153,545

Revenues less expenses					112,898		14,940		127,838
Income taxes—Note A					37,348		9,323		46,671

Results of operations before corporate overhead and interest expenses				$	75,550	$	5,617	$	81,167

			United States		Canada		Total
			(in thousands)
Year Ended December 31, 2000
Revenues
	From unaffiliated customers		$	207,656	$	38,072	$	245,728
	From affiliates			18				18

Total revenues				207,674		38,072		245,746

Production expenses				49,056		8,809		57,865
Exploration				5,533		2,442		7,975
Depreciation, depletion and amortization				51,973		13,196		65,169
Abandonment and impairment of gas and oil properties				2,327		1,091		3,418

		Total expenses		108,889		25,538		134,427

Revenues less expenses				98,785		12,534		111,319
Income taxes—Note A				31,994		5,841		37,835

Results of operations before corporate overhead and interest expenses			$	66,791	$	6,693	$	73,484

Note A—Income tax expenses have been reduced by nonconventional fuel-tax credits of $4.9 million in 2002, $5 million in 2001 and $4.7 million in 2000. The availability of these credits ended after December 31, 2002.

Estimated Quantities of Proved Gas and Oil Reserves

The table below shows the estimated proved reserves owned by the company. Estimates of U.S. reserves were made by Ryder Scott Company, H. J. Gruy and Associates, Inc., Netherland, Sewell & Associates, and Malkewicz Hueni Associates, Inc., independent reservoir engineers. Estimated Canadian reserves were prepared by Gilbert Laustsen Jung Associates Ltd. and Sproule Associates Ltd. Reserve estimates 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 gas and oil reserves reported were located in the United States and Canada. Canadian properties were sold in the fourth quarter of 2002. The company does not have any long-term supply contracts with foreign governments or reserves of equity investees.

	United States		Natural Gas Canada		Total		United States		Oil Canada		Total
			(MMcf)						(Mbbl)
Proved Reserves
Balance at January 1, 2000	493,777		20,676		514,453		11,063		2,795		13,858
Revisions of estimates	25,662		(7,890	)	17,772		221		(64	)	157
Extensions and discoveries	123,155		2,511		125,666		1,532		208		1,740
Purchase of reserves in place	846		52,000		52,846		1		1,520		1,521
Sale of reserves in place	(1,885	)			(1,885	)	(17	)			(17	)
Production	(61,722	)	(7,241	)	(68,963	)	(1,484	)	(741	)	(2,225	)

Balance at December 31, 2000	579,833		60,056		639,889		11,316		3,718		15,034
Revisions of estimates	(36,528	)	1,341		(35,187	)	(1,950	)	(21	)	(1,971	)
Extensions and discoveries	175,423		7,144		182,567		1,515		340		1,855
Purchase of reserves in place	300,353				300,353		19,185				19,185
Sale of reserves in place	(19,072	)			(19,072	)	(531	)			(531	)
Production	(63,862	)	(6,712	)	(70,574	)	(1,797	)	(703	)	(2,500	)

Balance at December 31, 2001	936,147		61,829		997,976		27,738		3,334		31,072
Revisions of estimates	(108,570	)	701		(107,869	)	(800	)	122		(678	)
Extensions and discoveries	240,872		1,712		242,584		2,812		26		2,838
Purchase of reserves in place	42				42
Sale of reserves in place	(43,220	)	(59,433	)	(102,653	)	(270	)	(3,028	)	(3,298	)
Production	(74,865	)	(4,809	)	(79,674	)	(2,310	)	(454	)	(2,764	)

Balance at December 31, 2002	950,406		—		950,406		27,170		—		27,170

Proved-Developed Reserves
Balance at January 1, 2000	412,008		17,076		429,084		9,897		2,565		12,462
Balance at December 31, 2000	434,122		55,623		489,745		9,696		3,077		12,773
Balance at December 31, 2001	534,761		53,036		587,797		19,417		2,566		21,983
Balance at December 31, 2002	540,333		—		540,333		19,942		—		19,942

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. The year-end prices do not include any impact of hedging activities. The average year-end price per Mcf of proved natural gas reserves was $3.34 in 2002, $2.19 in 2001, and $8.74 in 2000. The average year-end price per barrel of proved oil and NGL reserves combined was $28.46 in 2002, $18.38 in 2001, and $25.04 in 2000. Year-end production costs, development costs and appropriate statutory income tax rates, with consideration of future tax rates already legislated, were used to compute the future net cash flows. The statutes allowing income tax credits for nonconventional fuels

expired for production after December 31, 2002. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop booked proved-undeveloped reserves amounted to $44.9 million, $65.3 million and $46.7 million in 2003, 2004 and 2005, respectively.

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.

Management considers a number of factors when making investment and operating decisions. They include estimates of probable and proved reserves, and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.

		Year Ended December 31,
		2002			2001
		United States			United States			Canada			Total
		(in thousands)			(in thousands)
Future cash inflows		$	3,951,706		$	2,541,716		$	192,762		$	2,734,478
Future production costs			(1,049,205	)		(798,431	)		(58,643	)		(857,074	)
Future development costs			(326,169	)		(266,097	)		(3,421	)		(269,518	)
Future income tax expenses			(768,402	)		(392,152	)		(38,767	)		(430,919	)

	Future net cash flows		1,807,930			1,085,036			91,931			1,176,967
10% annual discount to reflect timing of net cash flows			(908,304	)		(536,876	)		(35,789	)		(572,665	)

Standardized measure of discounted future net cash flows		$	899,626		$	548,160		$	56,142		$	604,302

2000
Future cash inflows					$	5,412,945		$	568,771		$	5,981,716
Future production costs						(955,827	)		(73,583	)		(1,029,410	)
Future development costs						(107,355	)		(2,900	)		(110,255	)
Future income tax expenses						(1,489,267	)		(182,537	)		(1,671,804	)

	Future net cash flows					2,860,496			309,751			3,170,247
10% annual discount to reflect timing of net cash flows						(1,316,114	)		(136,445	)		(1,452,559	)

Standardized measure of discounted future net cash flows					$	1,544,382		$	173,306		$	1,717,688

The principal sources of change in the standardized measure of discounted future net cash flows were:

		Year Ended December 31,
		2002			2001			2000
		(in thousands)
Beginning balance		$	604,302		$	1,717,688		$	446,796
	Sales of oil and gas produced, net of production costs		(202,556	)		(210,631	)		(187,881	)
	Net changes in prices and production costs		535,840			(1,978,853	)		1,638,170
	Extensions and discoveries, less related costs		298,032			133,866			492,398
	Revisions of quantity estimates		(128,917	)		(31,451	)		70,155
	Purchase of reserves in place		45			303,757			32,260
	Sale of reserves in place		(126,485	)		(41,225	)		(1,867	)
	Change in future development		(12,128	)		(70,979	)		(17,770	)
	Accretion of discount		60,430			171,769			44,680
	Net change in income taxes		(138,387	)		775,013			(776,276	)
	Change in production rate		(11,229	)		(125,725	)		(50,077	)
	Other		20,629			(38,927	)		27,100

	Net change		295,324			(1,113,386	)		1,270,892

Ending balance		$	899,626		$	604,302		$	1,717,688

Cost-of-Service Activities

The following information is provided with respect to cost-of-service gas and oil properties managed and developed by Wexpro and regulated by the Wexpro Agreement. Information on the standardized measure of future net cash flows has not been included for cost-of-service activities because the operations of and return on investment for such properties are regulated by the Wexpro Agreement.

Capitalized Costs

Capitalized costs for cost-of-service gas and oil properties net of the related accumulated depreciation and amortization were as follows:

	December 31,
	2002		2001		2000
	(in thousands)
Wexpro	$	204,157	$	198,373	$	155,374
Questar Gas		18,915		20,991		22,620

	$	223,072	$	219,364	$	177,994

Costs Incurred

Costs incurred by Wexpro for cost-of-service gas and oil producing activities were $26.7 million in 2002, $58.5 million in 2001 and $32.1 million in 2000.

Results of Operations

Following are the results of operations of the company's cost-of-service gas-and-oil-development activities, before corporate overhead and interest expenses.

			Year Ended December 31,
			2002		2001		2000
			(in thousands)
Revenues
	From unaffiliated companies		$	8,699	$	12,465	$	15,179
	From affiliates—Note A			94,827		88,936		73,721

		Total revenues		103,526		101,401		88,900
Production expenses				23,032		33,016		27,861

Depreciation and amortization				20,475		15,051		13,922

		Total expenses		43,507		48,067		41,783

Revenues less expenses				60,019		53,334		47,117
Income taxes				21,572		19,181		16,923

	Results of operations before corporate overhead and interest expenses		$	38,447	$	34,153	$	30,194

Note A—Primarily represents revenues received from Questar Gas pursuant to the Wexpro Agreement.

Estimated Quantities of Proved Gas and Oil Reserves

The following estimates were made by the company's reservoir engineers.

		Natural Gas		Oil
		(MMcf)		(Mbbl)
Proved Reserves
Balance at January 1, 2000		353,683		3,289
	Revisions of estimates	16,523		504
	Extensions and discoveries	50,351		234
	Production	(41,546	)	(579	)

Balance at December 31, 2000		379,011		3,448
	Revisions of estimates	(11,465	)	275
	Extensions and discoveries	76,042		479
	Production	(37,907	)	(515	)

Balance at December 31, 2001		405,681		3,687
	Revisions of estimates	(658	)	(122	)
	Extensions and discoveries	56,085		675
	Production	(41,208	)	(501	)

Balance at December 31, 2002		419,900		3,739

Proved-Developed Reserves
Balance at January 1, 2000		345,654		3,228
Balance at December 31, 2000		362,748		3,318
Balance at December 31, 2001		400,461		3,640
Balance at December 31, 2002		395,821		3,481

QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
Schedule of Valuation and Qualifying Accounts
December 31, 2002
(in thousands)

Column A Description	Column B Beginning Balance		Column C Amounts charged to expense		Column D Deductions for accounts written off		Column E Ending Balance
Year Ended December 31, 2002
Allowance for bad debts	$	2,849	$	1,207	$	297	$	3,759
Year Ended December 31, 2001
Allowance for bad debts		1,775		1,229		155		2,849
Year Ended December 31, 2000
Allowance for bad debts		1,350		431		6		1775

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

QMR has not changed its independent auditors or had any disagreements with them concerning accounting matters and financial statement disclosures within the last 24 months.

PART III

The Company, as the wholly owned subsidiary of a reporting company under the Act, is entitled to omit all information requested in PART III (Items 10-13).

PART IV

ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K.

(3) Exhibits. The following is a list of exhibits required to be filed as a part of this report in Item 14(c).

Exhibit No.		Description
3.1.	*	Articles of Incorporation dated April 27, 1988 for Utah Entrada Industries, Inc. (Exhibit No. 3.1. to the Company's Form 10 dated April 12, 2000.)
3.2.	*	Articles of Merger, dated May 20, 1988, of Entrada Industries, Inc., a Delaware corporation and Utah Entrada Industries, Inc, a Utah corporation. (Exhibit No. 3.2. to the Company's Form 10 dated April 12, 2000.)
3.3.	*	Articles of Amendment dated August 31, 1998, changing the name of Entrada Industries, Inc. to Questar Market Resources, Inc. (Exhibit No. 3.3. to the Company's Form 10 dated April 12, 2000.)
3.4.	*	Bylaws (as amended effective October 24, 2002.) (Exhibit No. 3.1. to the Company's Form 10-Q for the Quarter ending September 30, 2002.)
4.1.	*	Indenture dated as of March 1, 2001, between the Questar Market Resources, Inc. and Bank One, NA, as Trustee for the Company's Notes. (Exhibit No. 4.01. to the Company's Current Report on Form 8-K dated March 6, 2001.)
4.2.	*	Form of 7¹/2% Notes due 2011. (Exhibit No. 4.02. to the Company's Current Report on Form 8-K dated March 6, 2001.)
4.4.		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, the Fifth Amendment dated October 6, 2000, and the Sixth Amendment dated February 9, 2001. (Exhibit No. 4.1. to the Company's Form 10 dated April 12, 2000, for the U. S. Credit Agreement, and the First, Second and Third Amendments; Exhibit No. 4.1. to the Company's Form 10/A dated November 9, 2000, for the Fourth and Fifth Amendments. Exhibit No. 4.3. to the Company's Form 10-K Annual Report for 2000 for the Sixth Amendment; Exhibit No. 4.4. to the Company's Form 10-K Annual Report for 2001 for the Seventh Amendment.) The Eighth and Ninth Amendments dated April 15, 2002 and February 27, 2003 are filed as Exhibit 4.4. to this report.

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.	*	Stock Purchase Agreement among the Company, Shenandoah Energy and Shenandoah Energy's stockholders. (Exhibit No. 10.2. to the Company's Current Report on Form 8-K dated July 31, 2001.)
Ratio of earnings to fixed charges.
Subsidiary Information. Power of Attorney.
99		Certification of C. B. Stanley and S. E. Parks.

*: Exhibits so marked have been filed with the Securities and Exchange Commission as part of the referenced filing and are incorporated herein by reference.

(b) The Company did not file a Current Report on Form 8-K during the fourth quarter of 2002.

GLOSSARY OF COMMONLY USED GAS AND OIL 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; 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.

"EMMdth" means million decatherms of natural gas equivalents.

"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.

"MBbl" means thousand barrels.

"Mcf" means thousand cubic feet.

"Mcfe" means thousand cubic feet of natural gas equivalents.

"MDth" means thousand decatherms.

"MMbbl" means million barrels.

"MMbtu" means million British thermal units.

"MMcf" means million cubic feet.

"MMcfe" means million cubic feet of natural gas equivalents.

"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.

For a more complete definition of proved reserves, please refer to SEC Regulation S-X paragraph 210.4-10(a)(2i)(2ii)(2iii)(3) and (4) available on the SEC web site.

"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.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 27th day of March, 2003.

		QUESTAR MARKET RESOURCES, INC. (Registrant)
		By:		/s/ C. B. STANLEY C. B. Stanley President & Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/ C. B. STANLEY C. B. Stanley		President & Chief Executive Officer Director (Principal Executive Officer)
/s/ S. E. PARKS S. E. Parks		Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)
/s/ B. KURTIS WATTS B. Kurtis Watts Manager, Accounting (Principal Accounting Officer)
R. D. Cash Patrick J. Early L. Richard Flury James A. Harmon Gary G. Michael G. L. Nordloh Keith O. Rattie C. B. Stanley		Chairman of the Board; Director Director Director Director Director Director Director Director

March 27, 2003

Date

*By

/s/ C. B. STANLEY

C. B. Stanley, Attorney in Fact

CERTIFICATION

I, C. B. Stanley, certify that:

1.

I have reviewed this annual report on Form 10-K of Questar Market Resources, Inc.;

2.

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c): presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a): all significant deficiencies in the design or operation of internal controls that could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls;

6.: The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

March 27, 2003

Date

By:

/s/ C. B. STANLEY

C. B. Stanley
President and Chief Executive Officer

CERTIFICATION

I, S. E. Parks, certify that:

1.

I have reviewed this annual report on Form 10-K of Questar Market Resources, Inc.;

2.

3.

4.

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c): presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

a): all significant deficiencies in the design or operation of internal controls that could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls;

6.: The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

March 27, 2003

DateDate

By:

/s/ S. E. PARKS

S. E. Parks
Vice President, Treasurer, and Chief Financial Officer

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Exhibit No. 4.4

EIGHTH AMENDMENT TO US CREDIT AGREEMENT

THIS EIGHTH AMENDMENT TO US CREDIT AGREEMENT (herein called the "Amendment") made as of April 15, 2002 (herein called the "Effective Date"), by and among Questar Market Resources, Inc., a Utah corporation ("US Borrower"), Bank of America, N.A., individually and as administrative agent for the Lenders as defined below ("US Agent"), and the undersigned Lenders.

W I T N E S S E T H:

WHEREAS, US Borrower, US Agent and the lenders as signatories thereto (the "Lenders") entered into that certain US Credit Agreement dated as of April 19, 1999, as amended by that certain First Amendment to US Credit Agreement dated as of May 17, 1999, as amended by that certain Second Amendment to US Credit Agreement dated as of July 30, 1999, as amended by that certain Third Amendment to US Credit Agreement dated as of November 30, 1999, as amended by that certain Fourth Amendment to US Credit Agreement dated as of April 17, 2000, as amended by that certain Fifth Amendment to US Credit Agreement dated as of October 6, 2000, and as amended by that certain Sixth Amendment to US Credit Agreement dated as of February 9, 2001, and as amended by that certain Seventh Amendment to US Credit Agreement dated as of April 16, 2001 (the "Original Agreement"), for the purpose and consideration therein expressed, whereby the Lenders became obligated to make loans to US Borrower as therein provided; and

WHEREAS, US Borrower, US Agent and the undersigned Lenders desire to amend the Original Agreement for the purposes as provided herein;

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement, in consideration of the loans which may hereafter be made by Lenders to US Borrower, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows:

ARTICLE I.

Definitions and References

§1.1. Terms Defined in the Original Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this Amendment.

§1.2. Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this Section 1.2.

"Amendment" means this Eighth Amendment to US Credit Agreement.

"Amendment Documents" means this Amendment, the Assignment and Acceptance Documents and the New US Notes.

"Assignment and Acceptance Documents" means that certain Assignment and Acceptance executed by all Tranche B Lenders and New Lender in the form of Exhibit F to the Original Credit Agreement, assigning certain interests of the Tranche B Lenders, and all documents delivered pursuant thereto.

"Lenders" means the Original Lenders and the New Lender.

"New Lender" means SunTrust Bank.

"New US Notes" means collectively, (i) the Tranche B Notes dated as of April 15, 2002, executed by US Borrower and payable to the order of each Tranche B Lender and SunTrust Bank, in the form attached hereto as Exhibit A, and (ii) the Competitive Bid Note dated as of April 15,

2002, executed by US Borrower and payable to the order of SunTrust Bank, in form attached hereto as Exhibit B.

"US Credit Agreement" means the Original Agreement as amended hereby.

ARTICLE II.

Amendments to Original Agreement

§2.1. Amendment and Restatement of Annex I. Annex I to the Original Agreement is hereby amended and restated in its entirety to read as set forth in Annex I attached hereto and made a part hereof.

§"2.2. Fees. Sections 1.5 of the Original Agreement is hereby amended in its entirety to read as follows:

Section 1.5. Interest Rates and Fees.

"(a) Tranche A Loans. The following interest and fees shall be payable with respect to Tranche A Loans:

(i) Interest. Each Tranche A Loan that is a US Base Rate Loan shall bear interest on each day outstanding at the US Base Rate in effect on such day. Each Tranche A Loan that is a US Dollar Eurodollar Loan shall bear interest on each day during the related Eurodollar Interest Period at the related Adjusted US Dollar Eurodollar Rate in effect on such day.

(ii) Tranche A Commitment Fees. In consideration of each Tranche A Lender's commitment to make Tranche A Loans under this Agreement, US Borrower will pay to US Agent for the account of each Tranche A Lender a commitment fee determined on a daily basis by applying the Five-Year Commitment Fee Rate to its Tranche A Percentage Share of the amount by which the Tranche A Maximum Credit Amount exceeds the Tranche A Facility Usage on each day during the US Facility Commitment Period. This commitment fee shall be due and payable in arrears on the fifteenth day after the end of each Fiscal Quarter and at the end of the US Facility Commitment Period.

(b) Tranche B Loans. The following interest and fees shall be payable with respect to Tranche B Loans:

(i) Interest. Each Tranche B Loan that is a US Base Rate Loan shall bear interest on each day outstanding at the US Base Rate in effect on such day. Each Tranche B Loan that is a US Dollar Eurodollar Loan shall bear interest on each day during the related Eurodollar Interest Period at the related Adjusted US Dollar Eurodollar Rate in effect on such day.

(ii) Commitment Fees. In consideration of each Tranche B Lender's commitment to make Tranche B Loans under this Agreement, US Borrower will pay to US Agent for the account of each Tranche B Lender a commitment fee determined on a daily basis by applying the 364-Day Commitment Fee Rate to its Tranche B Percentage Share of the amount by which the Tranche B Maximum Credit Amount exceeds the outstanding principal balance of the Tranche B Loans on each day during the period from the date hereof until the Tranche B Maturity Date. This commitment fee shall be due and payable in arrears on the fifteenth day after the end of each Fiscal Quarter and on the Tranche B Maturity Date.

(c) Utilization Fees. During the period from April 15, 2002, until the latest of the Tranche B Conversion Date, the Conversion Date under the Canadian Agreement, and the Tranche D Maturity Date, US Borrower will pay to US Agent for the account of each Lender under the US Agreement and the Canadian Agreement, a utilization fee for each day on

which the Aggregate Facility Usage exceeds thirty three and one-third percent (33¹/3%) of the sum of (i) the US Maximum Credit Amount plus (ii) the Canadian Maximum Credit Amount; provided that, if the Tranche B Loans or Tranche C Loans have been converted to term loans, they shall be excluded from the calculation of utilization fees. The amount of the utilization fee shall be determined on a daily basis by applying the Utilization Fee Rate to each such Lender's Percentage Share of the Aggregate Facility Usage on each such day. This utilization fee shall be due and payable in arrears on each Interest Payment Date for US Base Rate Loans and at the end of the US Facility Commitment Period.

(d) Competitive Bid Loans. Each Competitive Bid Loan shall bear interest on each day outstanding at the Competitive Bid Rate for such Competitive Bid Loan.

(e) All US Loans. Notwithstanding the foregoing, if an Event of Default has occurred and is continuing, all US Loans shall bear interest on each day outstanding at the applicable Default Rate. Past due payments of principal and interest shall bear interest at the rates and in the manner set forth in the US Notes.

(f) Administrative Fees. In addition to all other amounts due to US Agent under the US Loan Documents, US Borrower will pay fees to US Agent as described in a letter agreement dated January 14, 1999, executed by US Agent and accepted and agreed to by US Borrower on January 15, 1999."

§2.3 Increase in Commitments. Section 1.1(f) of the Original Agreement is hereby deleted and replaced with the following:

"(f) Increase in Commitments. At any time which is during all of the Tranche B Revolving Period, the Tranche C Revolving Period and the Tranche D Revolving Period, (1) the Tranche C Maximum Credit Amount or the Tranche D Maximum Credit Amount and the Canadian Maximum Credit Amount and (2) the Tranche A Maximum Credit Amount or the Tranche B Maximum Credit Amount and the US Maximum Credit Amount may be increased, pro rata, by an aggregate amount of $10,000,000 or any higher integral multiple thereof not to exceed $50,000,000 at the request of Canadian Borrower and with the prior written consent of the US Agent and the Canadian Agent, which consent shall not be unreasonably withheld, and without the consent of any Lender provided that a new Lender becomes a party to the US Agreement and the Canadian Agreement with the same Percentage Share of the Tranche B Loans and the Canadian Obligations, and that such Lender agrees to all of the terms and conditions of the US Loan Documents and the Canadian Loan Documents. Each of US Agent and Canadian Agent are hereby authorized to execute and deliver amendments to the Loan Documents to effectuate the foregoing on behalf of all Lenders."

§2.4 Waivers and Amendments. The fourth sentence of Section 10.1 of the Original Agreement is hereby amended in its entirety to read as follows:

"This Agreement and the other US Loan Documents set forth the entire understanding between the parties hereto with respect to the transactions contemplated herein and therein and supersede all prior discussions and understandings with respect to the subject matter hereof and thereof, and no waiver, consent, release, modification or amendment of or supplement to this Agreement or the other US Loan Documents shall be valid or effective against any party hereto unless the same is in writing and signed by (i) if such party is US Borrower, by US Borrower, (ii) if such party is US Agent or US LC Issuer, by such party, (iii) in any provision requiring the consent of Tranche A Required Lenders, if such party is a Tranche A Lender, by such Tranche A Lender or by US Agent on behalf of Tranche A Lenders with the written consent of Tranche A Required Lenders, (iv) in any provision requiring the consent of Tranche B Required Lenders, if such party is a Tranche B Lender, by such Tranche B Lender or by US Agent on behalf of Tranche B Lenders with the written consent of Tranche B Required Lenders and (v) if such party is a Lender, by such Lender or by US Agent on behalf of Lenders with the written consent of

Required Lenders (which consent has already been given as to the termination of the US Loan Documents as provided in Section 10.10)."

§2.4 Lenders Schedule. The Lenders Schedule attached to the Original Agreement is deleted and Schedule 1 hereto is substituted therefor.

ARTICLE III.

Amendment Fee

§3.1. Amendment Fee. In consideration of US Agent and each Tranche B Lender's (including SunTrust Bank as a Tranche B Lender) agreement to enter into this Amendment, US Borrower will pay to US Agent for the account of each Tranche B Lender an amendment fee determined by applying seven and one-half (7.5) Basis Points to such Tranche B Lender's Percentage Share of the Tranche B Maximum Credit Amount. This amendment fee shall be due and payable on the Effective Date of this Amendment.

ARTICLE IV.

Conditions of Effectiveness

§4.1. Effective Date. This Amendment shall become effective as of the date first above written when, and only when, US Agent shall have received, at US Agent's office:

(i) US Agent shall have received, at US Agent's office a counterpart of this Amendment executed and delivered by US Borrower, Required Lenders and New Lender;

(ii) US Borrower shall have issued and delivered to US Agent, for subsequent delivery to the appropriate Lender, the New Notes with appropriate insertions, duly executed on behalf of US Borrower, dated the date hereof;

(iii) US Agent shall have received, at US Agent's office, a counterpart of each Assignment and Acceptance Document, duly executed and delivered by the parties thereto;

(iv) US Agent shall have received, at US Agent's office, a certificate of the Secretary or Assistant Secretary and of the President, Chief Financial Officer or Vice President of Administrative Services of US Borrower dated the date of this Amendment certifying: (a) that resolutions adopted in connection with the Original Agreement by the Board of Directors of the US Borrower authorize the execution, delivery and performance of this Amendment by US Borrower, (b) to the names and true signatures of the officers of the US Borrower authorized to sign this Amendment, and (c) that all of the representations and warranties set forth in Article V hereof are true and correct at and as of the time of such effectiveness;

(v) US Agent shall have received, at US Agent's office, a favorable opinion of Eric L. Dady, Senior Counsel for Restricted Persons, substantially in the form set forth in Exhibit C attached hereto.

(v) US Agent shall have received from US Borrower, all fees and reimbursements to be paid to US Agent pursuant to any US Loan Documents, or otherwise due US Agent, including fees and disbursements of US Agent's attorneys.

ARTICLE V.

Representations and Warranties

§5.1. Representations and Warranties of Borrower. In order to induce US Agent and Lenders to enter into this Amendment, US Borrower represents and warrants to US Agent that:

(a) The representations and warranties contained in Article V of the Original Agreement are true and correct at and as of the time of the effectiveness hereof.

(b) US Borrower has duly taken all action necessary to authorize the execution and delivery by it of this Amendment and to authorize the consummation of the transactions contemplated hereby and the performance of its obligations hereunder. US Borrower is duly authorized to borrow funds under the US Credit Agreement.

(c) The execution and delivery by US Borrower of this Amendment, the performance by US Borrower of its obligations hereunder and the consummation of the transactions contemplated herein do not and will not (a) conflict with any provision of (i) any Law, (ii) the organizational documents of US Borrower, or (iii) any agreement, judgment, license, order or permit applicable to or binding upon US Borrower, or (b) result in the acceleration of any Indebtedness owed by US Borrower, or (c) result in or require the creation of any Lien upon any assets or properties of US Borrower, except as expressly contemplated or permitted in the Loan Documents. Except as expressly contemplated in the Loan Documents no consent, approval, authorization or order of, and no notice to or filing with any Tribunal or third party is required in connection with the execution, delivery or performance by US Borrower of this Amendment or to consummate any transactions contemplated herein.

(d) This Amendment is a legal, valid and binding obligation of US Borrower, enforceable in accordance with its terms, except as such enforcement may be limited by bankruptcy, insolvency or similar Laws of general application relating to the enforcement of creditors' rights and by equitable principles of general application relating to the enforcement of creditor's rights.

ARTICLE VI.

Miscellaneous

§6.1. Ratification of Agreements. The Original Agreement as hereby amended is hereby ratified and confirmed in all respects. The US Loan Documents, as they may be amended or affected by the various Amendment Documents, are hereby ratified and confirmed in all respects. Any reference to the US Credit Agreement in any Loan Document shall be deemed to be a reference to the Original Agreement as hereby amended. Any reference to the Lenders or the Lender Parties in any Loan Document shall be deemed to include New Lender. Any reference to the Tranche A Notes, the Tranche B Notes and the Competitive Bid Notes in any other US Loan Document shall be deemed to include a reference to the New US Notes issued and delivered pursuant to this Amendment. The execution, delivery and effectiveness of this Amendment and each of the New US Notes shall not, except as expressly provided herein or therein, operate as a waiver of any right, power or remedy of Lenders under the US Credit Agreement, the US Notes, or any other US Loan Document nor constitute a waiver of any provision of the US Credit Agreement, the US Notes or any other US Loan Document.

§6.2. Survival of Agreements; Cumulative Nature. All of Restricted Persons' various representations, warranties, covenants and agreements herein shall survive the execution and delivery of this Amendment and the other Amendment Documents and the performance hereof and thereof, including without limitation the making or granting of the US Loans and the delivery of the New US Notes and shall further survive until all of the US Obligations are paid in full to each Lender Party and all of Lender Parties' obligations to US Borrower are terminated. All statements and agreements contained in any certificate or instrument delivered by any Restricted Person hereunder or under the US Credit Agreement to any Lender Party shall be deemed representations and warranties by US Borrower or agreements and covenants of US Borrower under this Amendment and under the US Credit Agreement. The representations, warranties, indemnities, and covenants made by Restricted Persons in the US Loan Documents, and the rights, powers, and privileges granted to Lender Parties in the US Loan Documents, are cumulative, and, except for expressly specified waivers and consents, no Loan Document shall be construed in the context of another to diminish, nullify, or otherwise reduce the benefit to any Lender Party of any such representation, warranty, indemnity, covenant, right, power or privilege. In particular and without limitation, no exception set out in this Amendment or any other Amendment Document to any representation, warranty, indemnity, or covenant herein or therein

contained shall apply to any similar representation, warranty, indemnity, or covenant contained in any other Loan Document, and each such similar representation, warranty, indemnity, or covenant shall be subject only to those exceptions which are expressly made applicable to it by the terms of the various US Loan Documents.

§6.3. Loan Documents. This Amendment, the Assignment and Acceptance Documents and the New US Notes are each a US Loan Document, and all provisions in the US Credit Agreement pertaining to US Loan Documents apply hereto and thereto.

§6.4. Governing Law. This Amendment, the Assignment and Acceptance Documents and the New US Notes shall each be governed by and construed in accordance the laws of the State of Utah and any applicable laws of the United States of America in all respects, including construction, validity and performance. US Borrower hereby irrevocably submits itself and each other Restricted Person to the non-exclusive jurisdiction of the state and federal courts sitting in the State of Utah and agrees and consents that service of process may be made upon it or any Restricted Person in any legal proceeding relating to the Amendment Documents or the Obligations by any means allowed under Utah or federal law.

§6.5. Counterparts. This Amendment may be separately executed in any number of counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. This Amendment may be validly executed and delivered by facsimile or other electronic transmission.

THIS AMENDMENT AND THE OTHER US LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

[The remainder of this page has been intentionally left blank.]

IN WITNESS WHEREOF, this Amendment is executed as of the date first above written.

		QUESTAR MARKET RESOURCES, INC. US Borrower
		By:		G. L. Nordloh President and Chief Executive Officer
				Mailing Address: P.O. Box 45433 Salt Lake City, Utah 84145 Attention: Martin H. Craven
				Street Address: 180 East 100 South Salt Lake City, Utah 84111 Telephone: (801) 324-5077 Fax: (801) 324-5483
		BANK OF AMERICA, N.A. Administrative Agent, US LC Issuer and Lender
		By:		Name: Title:
		TORONTO DOMINION (TEXAS), INC. Lender
		By:		Name: Title:
		MIZUHO CORPORATE BANK, LTD., formerly known as The Industrial Bank of Japan, Limited Lender
		By:		Name: Title:
		SUMITOMO MITSUI BANKING CORPORATION, formerly known as The Sumitomo Bank, Limited Lender
		By:		Name: Title:
		BANK OF MONTREAL Lender
		By:		James Whitmore Director
		BANK ONE, NA (MAIN OFFICE CHICAGO) Lender
		By:		Name: Title:

		WELLS FARGO BANK, N.A., as successor to First Security Bank, N.A. Lender
		By:		Name: Title:
		MELLON BANK, N.A. Lender
		By:		Roger E. Howard Vice President
		U.S. BANK NATIONAL ASSOCIATION Lender
		By:		Matthew J. Purchase Assistant Vice President
		THE BANK OF TOKYO-MITSUBISHI, LTD., HOUSTON AGENCY Lender
		By:		Name: Title:
		SUNTRUST BANK Lender
		By:		Name: Title:

EXHIBIT A

Tranche B Note
PROMISSORY NOTE

US$

[Tranche B Note]

April 15, 2002

FOR VALUE RECEIVED, the undersigned, Questar Market Resources, Inc., a Utah corporation (herein called "Borrower"), hereby promises to pay to the order of SUNTRUST BANK (herein called "Lender"), the principal sum of Dollars (US$ ), or, if greater or less, the aggregate unpaid principal amount of the Tranche B Loans made under this Note by Lender to Borrower pursuant to the terms of the Credit Agreement (as hereinafter defined), together with interest on the unpaid principal balance thereof as hereinafter set forth, both principal and interest payable as herein provided in lawful money of the United States of America at the offices of US Agent under the Credit Agreement, 901 Main Street, Dallas, Texas or at such other place within Dallas County, Texas, as from time to time may be designated by the holder of this Note.

This Note (a) is issued and delivered under that certain US Credit Agreement dated as of April 19, 1999 among Borrower, Bank of America, N.A., individually and as administrative agent ("US Agent"), and the lenders (including Lender) referred to therein (herein, as from time to time supplemented, amended or restated, called the "Credit Agreement"), and is a "Tranche B Note" as defined therein, (b) is subject to the terms and provisions of the Credit Agreement, which contains provisions for payments and prepayments hereunder and acceleration of the maturity hereof upon the happening of certain stated events, and (c) is given in partial renewal and extension (but not in extinguishment or novation) of (i) that certain Promissory Note dated April 17, 2000, executed and delivered by Borrower and payable to the order of Toronto Dominion (Texas), Inc., in the stated principal amount of US $3,333,333.33, (ii) that certain Promissory Note dated April 17, 2000, executed and delivered by Borrower and payable to the order of The Industrial Bank of Japan, Limited, in the stated principal amount of US $1,666,666.67, and (iii) that certain Promissory Note dated April 17, 2000, executed and delivered by Borrower and payable to the order of Sumitomo Mitsui Banking Corporation, formerly known as The Sumitomo Bank, Limited, in the stated principal amount of US $1,666,666.67. Payments on this Note shall be made and applied as provided herein and in the Credit Agreement. Reference is hereby made to the Credit Agreement for a description of certain rights, limitations of rights, obligations and duties of the parties hereto and for the meanings assigned to terms used and not defined herein.

The principal amount of this Note, together with all interest accrued hereon, shall be due and payable in full on the Tranche B Maturity Date.

Tranche B Loans that are US Base Rate Loans (exclusive of any past due principal or interest) from time to time outstanding shall bear interest on each day outstanding at the US Base Rate in effect on such day; provided that if an Event of Default has occurred and is continuing, US Base Rate Loans shall bear interest on each day outstanding at the applicable Default Rate in effect on such day. On each Interest Payment Date Borrower shall pay to the holder hereof all unpaid interest which has accrued on the US Base Rate Loans to but not including such Interest Payment Date. Each Tranche B Loan that is a US Dollar Eurodollar Loan (exclusive of any past due principal or interest) shall bear interest on each day during the related Interest Period at the related Adjusted US Dollar Eurodollar Rate in effect on such day; provided that if an Event of Default has occurred and is continuing, such US Dollar Eurodollar Loan shall bear interest on each day outstanding at the applicable Default Rate in effect on such day. On each Interest Payment Date relating to such US Dollar Eurodollar Loan, Borrower shall pay to the holder hereof all unpaid interest which has accrued on such US Dollar Eurodollar Loan to but not including such Interest Payment Date.

All past due principal of and past due interest on the Loans shall bear interest on each day outstanding at the applicable Default Rate in effect on such day, and such interest shall be due and payable daily as it accrues. Notwithstanding the foregoing provisions of this paragraph: (a) this Note

shall never bear interest in excess of the Highest Lawful Rate, and (b) if at any time the rate at which interest is payable on this Note is limited by the Highest Lawful Rate (by the foregoing subsection (a) or by reference to the Highest Lawful Rate in the definitions of US Base Rate, Adjusted US Dollar Eurodollar Rate, and Default Rate), this Note shall bear interest at the Highest Lawful Rate and shall continue to bear interest at the Highest Lawful Rate until such time as the total amount of interest accrued hereon equals (but does not exceed) the total amount of interest which would have accrued hereon had there been no Highest Lawful Rate applicable hereto.

Notwithstanding the foregoing paragraph and all other provisions of this Note, in no event shall the interest payable hereon, whether before or after maturity, exceed the maximum amount of interest which, under applicable Law, may be charged on this Note, and this Note is expressly made subject to the provisions of the Credit Agreement which more fully set out the limitations on how interest accrues hereon. The term "applicable Law" as used in this Note shall mean the laws of the State of Utah or the laws of the United States, whichever laws allow the greater interest, as such laws now exist or may be changed or amended or come into effect in the future.

If this Note is placed in the hands of an attorney for collection after default, or if all or any part of the indebtedness represented hereby is proved, established or collected in any court or in any bankruptcy, receivership, debtor relief, probate or other court proceedings, Borrower and all endorsers, sureties and guarantors of this Note jointly and severally agree to pay reasonable attorneys' fees and collection costs to the holder hereof in addition to the principal and interest payable hereunder.

Borrower and all endorsers, sureties and guarantors of this Note hereby severally waive demand, presentment, notice of demand and of dishonor and nonpayment of this Note, protest, notice of protest, notice of intention to accelerate the maturity of this Note, declaration or notice of acceleration of the maturity of this Note, diligence in collecting, the bringing of any suit against any party and any notice of or defense on account of any extensions, renewals, partial payments or changes in any manner of or in this Note or in any of its terms, provisions and covenants, or any releases or substitutions of any security, or any delay, indulgence or other act of any trustee or any holder hereof, whether before or after maturity.

THIS NOTE AND THE RIGHTS AND DUTIES OF THE PARTIES HERETO SHALL BE GOVERNED BY THE LAWS OF THE STATE OF UTAH (WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW), EXCEPT TO THE EXTENT THE SAME ARE GOVERNED BY APPLICABLE FEDERAL LAW.

				QUESTAR MARKET RESOURCES, INC.
		By:		G. L. Nordloh President and Chief Executive Officer

EXHIBIT B

Competitive Bid Note

COMPETITIVE BID NOTE
[U.S. Facility]

April 15, 2002

FOR VALUE RECEIVED, the undersigned, Questar Market Resources, Inc., a Utah corporation ("Borrower"), hereby promises to pay to the order of SUNTRUST BANK ("Lender"), the aggregate unpaid principal amount of all Competitive Bid Loans made under this Note by Lender to Borrower pursuant to the terms of the Credit Agreement (as hereinafter defined), together with interest on the unpaid principal balance thereof as hereinafter set forth, both principal and interest payable as herein provided in lawful money of the United States of America at the offices of US Agent under the Credit Agreement, 901 Main Street, Dallas, Texas or at such other place within Dallas County, Texas, as from time to time may be designated by the holder of this Note.

This Note (a) is issued and delivered under that certain US Credit Agreement dated as of April 19, 1999, among Borrower, Bank of America, N.A., individually and as administrative agent ("US Agent"), and the lenders (including Lender) referred to therein (herein, as from time to time supplemented, amended or restated, called the "Credit Agreement"), and is a "Competitive Bid Note" as defined therein, and (b) is subject to the terms and provisions of the Credit Agreement, which contains provisions for payments and prepayments hereunder and acceleration of the maturity hereof upon the happening of certain stated events. Payments on this Note shall be made and applied as provided herein and in the Credit Agreement. Reference is hereby made to the Credit Agreement for a description of certain rights, limitations of rights, obligations and duties of the parties hereto and for the meanings assigned to terms used and not defined herein.

For the purposes of this Note, "Competitive Bid Rate Payment Date" means, with respect to each Competitive Bid Loan: (i) the day on which the related Competitive Bid Interest Period ends, and (ii) any day on which past due interest or past due principal is owed hereunder with respect to such Competitive Bid Loan and is unpaid. If the terms hereof or of the Credit Agreement provide that payments of interest or principal with respect to such Competitive Bid Loan shall be deferred from one Competitive Bid Rate Payment Date to another day, such other day shall also be a Competitive Bid Rate Payment Date.

The principal amount of this Note and interest accrued hereon, shall be due and payable as set forth in the Credit Agreement, and shall in any event be due in full on the last day of the US Facility Commitment Period.

Each Competitive Bid Loan (exclusive of any past due principal or past due interest) shall bear interest on each day during the related Competitive Bid Interest Period at the Competitive Bid Rate in effect on such day for such Competitive Bid Loan, provided that if an Event of Default has occurred and is continuing such Competitive Bid Loan shall bear interest on each day outstanding at the applicable Default Rate in effect on such day. On each Competitive Bid Rate Payment Date relating to any Competitive Bid Loan, Borrower shall pay to the holder hereof all unpaid interest which has accrued on such Competitive Bid Loan to but not including such Competitive Bid Rate Payment Date.

All past due principal of and past due interest on Competitive Bid Loans shall bear interest on each day outstanding at the applicable Default Rate in effect on such day, and such interest shall be due and payable daily as it accrues. Notwithstanding the foregoing provisions of this paragraph: (a) this Note shall never bear interest in excess of the Highest Lawful Rate, and (b) if at any time the rate at which interest is payable on this Note is limited by the Highest Lawful Rate (by the foregoing clause (a) or by reference to the Highest Lawful Rate in the definitions of Competitive Bid Rate and Default Rate), this Note shall bear interest at the Highest Lawful Rate and shall continue to bear interest at the Highest Lawful Rate until such time as the total amount of interest accrued hereon

equals (but does not exceed) the total amount of interest which would have accrued hereon had there been no Highest Lawful Rate applicable hereto.

		QUESTAR MARKET RESOURCES, INC.

		By:		G. L. Nordloh President and Chief Executive Officer

EXHIBIT C

Opinion of Counsel for Restricted Persons

DEFINED TERMS

LENDERS SCHEDULE

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Exhibit No. 4.4

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Exhibit No. 4.5.

NINTH AMENDMENT TO US CREDIT AGREEMENT

THIS NINTH AMENDMENT TO US CREDIT AGREEMENT (herein called the "Amendment") made as of February 27, 2003, by and among Questar Market Resources, Inc., a Utah corporation ("US Borrower"), Bank of America, N.A., individually and as administrative agent for the Lenders as defined below ("US Agent"), and the undersigned Lenders.

W I T N E S S E T H:

WHEREAS, US Borrower, US Agent and the lenders as signatories thereto (the "Lenders") entered into that certain US Credit Agreement dated as of April 19, 1999 (as heretofore amended, the "Original Agreement"), for the purpose and consideration therein expressed, whereby the Lenders became obligated to make loans to US Borrower as therein provided; and

WHEREAS, US Borrower, US Agent and the undersigned Lenders desire to amend the Original Agreement for the purposes as provided herein;

ARTICLE I.

Definitions and References

Section 1.1. Terms Defined in the Original Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this Amendment.

Section 1.2. Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this Section 1.2.

"Amendment" means this Ninth Amendment to US Credit Agreement.

"US Credit Agreement" means the Original Agreement as amended hereby.

ARTICLE II.

Amendments to Original Agreement

Section 2.1. Hedging Contracts. Section 7.10(i)(B) of the Original Agreement is hereby amended in its entirety to read as follows:

"(B) such contracts do not require any Restricted Person to provide any Lien or letter of credit to secure the Restricted Persons' obligations thereunder, other than Liens on cash or cash equivalents and letters of credit; provided that the aggregate amount of cash and cash equivalents subject to Liens securing such contracts and the undrawn amount of all letters of credit securing such contracts shall not exceed (i) US $70,000,000 at any time through and including May 1, 2003, and (ii) US $30,000,000 at any time thereafter."

ARTICLE III.

Waiver

Section 3.1. Waiver. US Borrower has informed US Agent that the aggregate amount of cash and cash equivalents subject to Liens securing Hedging Contracts and the undrawn amount of all letters of credit securing Hedging Contracts ("Cash Collateral") exceeds the US $30,000,000 limit set

forth in Section 7.10(i) of the Original Agreement. US Agent and the undersigned Lenders hereby (a) waive any violation of Section 7.10(i) that existed prior to the date hereof due to Cash Collateral exceeding such limit, and (b) waive any Default or Event of Default resulting from such violation.

ARTICLE IV.

Conditions of Effectiveness

Section 4.1. Effective Date. This Amendment shall become effective as of the date first above written when, and only when, US Agent shall have received, at US Agent's office:

(i) a counterpart of this Amendment executed and delivered by US Borrower and Required Lenders;

(ii) a certificate of the Secretary or Assistant Secretary and of the President, Chief Financial Officer or Vice President of Administrative Services of US Borrower dated the date of this Amendment certifying: (a) that resolutions adopted in connection with the Original Agreement by the Board of Directors of the US Borrower authorize the execution, delivery and performance of this Amendment by US Borrower, (b) to the names and true signatures of the officers of the US Borrower authorized to sign this Amendment, and (c) that all of the representations and warranties set forth in Article V hereof are true and correct at and as of the time of such effectiveness; and

(iii) all fees and reimbursements to be paid to US Agent pursuant to any US Loan Documents, or otherwise due US Agent, including fees and disbursements of US Agent's attorneys.

ARTICLE V.

Representations and Warranties

Section 5.1. Representations and Warranties of Borrower. In order to induce US Agent and Lenders to enter into this Amendment, US Borrower represents and warrants to US Agent that:

(a) The representations and warranties contained in Article V of the Original Agreement are true and correct at and as of the time of the effectiveness hereof.

ARTICLE VI.

Miscellaneous

Section 6.1. Ratification of Agreements. The Original Agreement as hereby amended is hereby ratified and confirmed in all respects. The US Loan Documents, as they may be amended or affected by this Amendment, are hereby ratified and confirmed in all respects. Any reference to the US Credit Agreement in any Loan Document shall be deemed to be a reference to the Original Agreement as hereby amended. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of Lenders under the US Credit Agreement, the US Notes, or any other US Loan Document nor constitute a waiver of any provision of the US Credit Agreement, the US Notes or any other US Loan Document.

Section 6.2. Survival of Agreements; Cumulative Nature. All of US Borrower's various representations, warranties, covenants and agreements herein shall survive the execution and delivery of this Amendment and the performance hereof, including without limitation the making or granting of the US Loans, and shall further survive until all of the US Obligations are paid in full to each Lender Party and all of Lender Parties' obligations to US Borrower are terminated. All statements and agreements contained in any certificate or instrument delivered by any Restricted Person hereunder or under the US Credit Agreement to any Lender Party shall be deemed representations and warranties by US Borrower or agreements and covenants of US Borrower under this Amendment and under the US Credit Agreement. The representations, warranties, indemnities, and covenants made by Restricted Persons in the US Loan Documents, and the rights, powers, and privileges granted to Lender Parties in the US Loan Documents, are cumulative, and, except for expressly specified waivers and consents, no Loan Document shall be construed in the context of another to diminish, nullify, or otherwise reduce the benefit to any Lender Party of any such representation, warranty, indemnity, covenant, right, power or privilege. In particular and without limitation, no exception set out in this Amendment to any representation, warranty, indemnity, or covenant herein contained shall apply to any similar representation, warranty, indemnity, or covenant contained in any other Loan Document, and each such similar representation, warranty, indemnity, or covenant shall be subject only to those exceptions which are expressly made applicable to it by the terms of the various US Loan Documents.

Section 6.3. Loan Documents. This Amendment is a US Loan Document, and all provisions in the US Credit Agreement pertaining to US Loan Documents apply hereto.

Section 6.4. Governing Law. This Amendment shall be governed by and construed in accordance the laws of the State of Utah and any applicable laws of the United States of America in all respects, including construction, validity and performance. US Borrower hereby irrevocably submits itself and each other Restricted Person to the non-exclusive jurisdiction of the state and federal courts sitting in the State of Utah and agrees and consents that service of process may be made upon it or any Restricted Person in any legal proceeding relating to the Amendment Documents or the Obligations by any means allowed under Utah or federal law.

Section 6.5. Counterparts. This Amendment may be separately executed in any number of counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. This Amendment may be validly executed and delivered by facsimile or other electronic transmission.

[THE REMAINDER OF THIS PAGE HAS BEEN INTENTIONALLY LEFT BLANK.]

IN WITNESS WHEREOF, this Amendment is executed as of the date first above written.

		QUESTAR MARKET RESOURCES, INC. US Borrower
		By:		C.B. Stanley President and Chief Executive Officer
				Mailing Address: P.O. Box 45433 Salt Lake City, Utah 84145 Attention: Martin H. Craven
				Street Address: 180 East 100 South Salt Lake City, Utah 84111 Telephone: (801) 324-5077 Fax: (801) 324-5483
		BANK OF AMERICA, N.A. Administrative Agent, US LC Issuer and Lender
		By:		Name: Title:
		TORONTO DOMINION (TEXAS), INC. Lender
		By:		Name: Title:
		MIZUHO CORPORATE BANK, LTD., formerly known as The Industrial Bank of Japan, Limited Lender
		By:		Name: Title:
		SUMITOMO MITSUI BANKING CORPORATION, formerly known as The Sumitomo Bank, Limited Lender
		By:		Name: Title:
		BANK OF MONTREAL Lender
		By:		Name: Title:
		BANK ONE, NA (MAIN OFFICE CHICAGO) Lender
		By:		Name: Title:

		WELLS FARGO BANK, N.A., as successor to First Security Bank, N.A. Lender
		By:		Name: Title:
		MELLON BANK, N.A. Lender
		By:		Name: Title:
		U.S. BANK NATIONAL ASSOCIATION Lender
		By:		Name: Title:
		THE BANK OF TOKYO-MITSUBISHI, LTD., HOUSTON AGENCY Lender
		By:		Name: Title:
		SUNTRUST BANK Lender
		By:		Name: Title:

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Exhibit No. 4.5.

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Exhibit 12.

Questar Market Resources and Subsidiaries
Ratio of Earnings to Fixed Charges

	Year Ended December 31,
	2002			2001			2000
	(Dollars In Thousands)
Earnings
Income before income taxes	$	151,094		$	155,352		$	116,426
Plus debt expense		34,705			22,872			22,922
Plus interest portion of rental expense		1,182			1,112			985
Less company's share of earnings of equity investees		(3,997	)		(1,265	)		(2,776	)
Plus distributions of equity investees		7,218			553			659
Less minority interest in loss		(484	)		(359	)
Plus minority interest in earnings								338

	$	189,738		$	178,265		$	138,554

Fixed Charges
Debt expense	$	34,705		$	22,872		$	22,922
Plus interest portion of rental expense		1,182			1,112			985

	$	35,887		$	23,984		$	23,907

Ratio of Earnings to Fixed Charges		5.29			7.43			5.80

For purposes of this presentation, earnings represent income before income taxes adjusted for fixed charges, equity in minority interest, earnings and distributions of equity investees. Fixed charges consist of total interest charges (expensed and capitalized), amortization of debt issuance costs, and the interest portion of rental expense estimated at 50%. Income before income taxes includes Questar Market Resources' share of pretax earnings of equity investees.

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Exhibit 12.

Questar Market Resources and Subsidiaries Ratio of Earnings to Fixed Charges

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Exhibit No. 21.

SUBSIDIARY INFORMATION

Registrant Questar Market Resources, Inc., has the following subsidiaries: Wexpro Company, Questar Exploration and Production Company, Questar Energy Trading Company, Questar Gas Management Company. Questar Exploration and Production is a Texas corporation. The other listed companies are incorporated in Utah.

Questar Exploration and Production has two wholly-owned subsidiaries, Shenandoah Energy, Inc. and Questar URC Company, which are both Delaware corporations.

Questar Exploration and Production also does business under the names Universal Resources Corporation, Questar Energy Company and URC Corporation.

Questar Energy Trading Company has two subsidiaries, URC Canyon Creek Compression Company and Questar Power Generation Company; both entities are Utah corporations.

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Exhibit No. 21.

SUBSIDIARY INFORMATION

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Exhibit No. 24.

POWER OF ATTORNEY

We, the undersigned directors of Questar Market Resources, Inc., hereby severally constitute C. B. Stanley and S. E. Parks, and each of them acting alone, our true and lawful attorneys, with full power to them and each of them to sign for us, and in our names in the capacities indicated below, the Annual Report on Form 10-K for 2002 and any and all amendments to be filed with the Securities and Exchange Commission by Questar Market Resources, Inc., hereby ratifying and confirming our signatures as they may be signed by the attorneys appointed herein to the Annual Report on Form 10-K for 2002 and any and all amendments to such Report.

Witness our hands on the respective dates set forth below.

Signature	Title	Date
/s/ R. D. CASH R. D. Cash	Chairman of the Board	2-11-03
/s/ K. O. RATTIE K. O. Rattie	Vice Chairman	2-11-03
/s/ C. B. STANLEY C. B. Stanley	President & Chief Executive Officer Director	2-11-03
/s/ P. J. EARLY P. J. Early	Director	2-11-03
/s/ L. RICHARD FLURY L. Richard Flury	Director	2-11-03
/s/ JAMES A. HARMON James A. Harmon	Director	2-11-03
/s/ GARY G. MICHAEL Gary G. Michael	Director	2-11-03
/s/ GARY L. NORDLOH Gary L. Nordloh	Director	2-11-03

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Exhibit No. 24.

POWER OF ATTORNEY

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Exhibit No. 99.

Certification Pursuant to
18 U.S.C. Section 1350,
as adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Questar Market Resources, Inc. (the "Company") on Form 10-K for 2002, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), C. B. Stanley, President and Chief Executive Officer of the Company, and S. E. Parks, Vice President, Treasurer and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

		QUESTAR MARKET RESOURCES, INC.
March 27, 2003
		/s/ C. B. STANLEY C. B. Stanley President and Chief Executive Officer
March 27, 2003
		/s/ S. E. PARKS S. E. Parks Vice President, Treasurer and Chief Financial Officer

This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

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Exhibit No. 99.