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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

[X]

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003 OR

[   ]

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

      87-0287750

(State or other jurisdiction of

           (I.R.S. Employer

incorporation or organization)

         Identification No.)

180 East 100 South, P.O. Box 45601, Salt Lake City, Utah

      84145-0601

(Address of principal executive offices)

         (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:

7 ½% 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  Ö_ 

No  _   

State the aggregate market value of the voting stock held by nonaffili­ates of the registrant as of February 27, 2004.  $0.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of February 27, 2004:  4,309,427 shares of Common Stock, $1.00 par value.  (All shares are owned by Questar Corporation.)

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)  Yes              No   Ö  

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

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)

Item 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

PART IV

Item 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND

REPORTS ON FORM 8-K

SIGNATURES

Glossary of Commonly Used Terms

bbl

Barrel-42 U. S. gallons, a common unit of measurement of crude oil.

basis

The difference between a reference or benchmark commodity price and the corresponding selling prices at various regional sales points.

bcf

One billion cubic feet, a common unit of measurement of natural gas.

bcfe

One billion cubic feet of natural gas equivalent. Oil volume is converted to natural gas equivalent using the ratio of one barrel of crude oil to 6,000 cubic feet of natural gas.

btu

One British Thermal Unit – a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

cash flow hedge

A derivative instrument that complies with Statement of Financial Accounting Standards (“SFAS”) 133, as amended, and is used to reduce the exposure to variability in cash flows from the forecasted physical sale of gas and oil production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted physical sale.

development well

A well drilled into a known producing formation in a previously discovered field.

dew point

A specific temperature and pressure at which hydrocarbons condense to form a liquid.

dry hole

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

Decatherms or ten therms. One dth equals one million Btu or approximately one Mcf.

exploratory well

A well drilled into a previously untested geologic structure to determine the presence of gas or oil.

futures contract

An exchange-traded legal contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price.

gross

“Gross” natural gas and oil wells or “gross” acres equals the total number of wells or acres in which the Company has an interest.

hedging

The use of derivative commodity and interest rate instruments to reduce financial exposure to commodity price and interest rate volatility.

Mbbls

One thousand barrels.

Mcf

One thousand cubic feet.

Mcfe

One thousand cubic feet of natural gas equivalents.

Mdth

One thousand decatherms.

MMbbls

   One million barrels.

MMbtu

One million British Thermal Units.

MMcf

One million cubic feet.

MMcfe

One million cubic feet of natural gas equivalents

MMdth

One million decatherms.

natural gas liquids

Liquid hydrocarbons that are extracted and separated from the natural gas

(NGL)

 stream.  NGL products include ethane, propane, butane, natural gasoline and heavier hydrocarbons.

net

“Net” gas and oil wells or “net” acres are determined by multiplying gross wells or acres by the Company’s working interest in those wells or acres.

proved reserves

  “Proved reserves” means those quantities of natural gas and crude oil, condensate, and natural gas liquids on a net revenue interest basis, which geological and engineering data demonstrate with reasonable certainty to be recoverable under existing economic and operating conditions. “Proved developed reserves” include proved developed producing reserves and proved developed behind-pipe reserves. “Proved developed producing reserves” include only those reserves expected to be recovered from existing completion intervals in existing wells. “Proved undeveloped reserves” include those reserves expected to be recovered from new wells on proved undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

reservoir

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.

wet gas

Unprocessed natural gas that contains a mixture of heavier hydrocarbons including ethane, propane, butane, and natural gasoline.

working interest

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.

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 (“Exchange Act”). 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; changes in rate-regulatory policies; regulation of the Wexpro Agreement; availability of gas and oil properties for sale or exploration and land-access issues; 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; changes in customers' credit ratings; competition from other forms of energy, other pipelines and storage facilities; the effect of accounting policies issued periodically by accounting standard-setting bodies; terrorist attacks or acts of war; changes in the business or financial conditi on of Questar Market Resources, Inc. and changes in credit ratings.

FORM 10-K

ANNUAL REPORT, 2003

PART I

ITEM 1.  BUSINESS.

General

Questar Market Resources Inc., (“Market Resources” or the “Company”) is a wholly owned subsidiary of Questar Corporation (“Questar”) and is the primary growth driver within Questar. As shown in the following organization chart, Market Resources conducts its operations through several subsidiaries. Questar Exploration and Production Company (“Questar E&P”) acquires and develops gas and oil properties. Wexpro Company (“Wexpro”) develops cost-of-service reserves for Questar Gas Company. Questar Gas Management Company (“Gas Management”) provides gas gathering and processing services for affiliates and third parties. Questar Energy Trading Company (“Energy Trading”) markets equity and third-party gas and oil, provides risk-management services, and owns and operates an underground gas-storage reservoir.

E&P, General

Questar E&P conducts a blended program of lower risk development drilling and low-risk reserve acquisitions. It plans to take some exploration risks in 2004 by drilling one or more wells to evaluate deeper potential on its existing acreage at Pinedale (western Wyoming) and the Uinta Basin (eastern Utah). It maintains a geographic balance and diversity with core activities in the Rocky Mountain region of Wyoming, Utah and Colorado and the Midcontinent region of Oklahoma, Texas and Louisiana.

Natural gas remains the primary focus of Market Resources exploration and production (E&P) strategy. As of year-end 2003, Questar E&P had proved nonregulated reserves (reserves excluding quantities reported as cost-of-service reserves) of 999.2 bcf of gas and 26.6 MMbbls of oil and NGLs. On an energy-equivalent ratio, natural gas comprised approximately 86 percent of proved nonregulated reserves.

E&P Growth Strategy

During the last three years Questar E&P has focused on drilling wells and expanding production volumes from the Pinedale Anticline area in western Wyoming. On a combined basis, Questar E&P and Wexpro have an approximate 62 percent average working interest in 14,800 acres in the Mesa area. For 2003, net nonregulated production from Questar E&P's wells at Pinedale was 15.2 bcfe compared to 8.6 bcfe a year earlier.

In 2004 Market Resources will evaluate the deeper potential of the Pinedale acreage. To date, the Company has only drilled down to depths of about 14,500 feet on the Pinedale structure. A number of potentially productive deeper formations at depths of up to 19,500 feet remain untested. While there are examples of prolific production from these formations and depths elsewhere in the Rockies, the deeper potential on the Company’s acreage has not been evaluated. Only one well, 20 miles to the south of Market Resources’ acreage, has been drilled below the Mesaverde Formation on the Pinedale Anticline. Drilled in 1972, the well encountered a series of potential reservoir horizons but had mechanical problems and was never tested conclusively.

To date Market Resources has drilled three Pinedale wells on 20-acre spacing to evaluate optimum well density. The three new wells were direct 20-acre offsets to the Mesa Unit #2 well drilled by a Market Resources affiliate in 1981; the well was completed in only four Lance Formation intervals. The well has produced approximately 1.0 bcfe, primarily from a single interval. Market Resources measured the reservoir pressure in the same interval for the three 20-acre pilot wells. The data indicates little depletion as a result of the original #2 well. During 2004, Market Resources plans to drill additional 20-acre pilot wells before seeking approval for field-wide 20-acre development. Except for reserves from the three currently producing 20-acre pilot wells, Market Resources has not booked any proved reserves on 20-acre locations at Pinedale.

During 2003 Questar E&P continued its gas-directed Wasatch formation development drilling program in the Uinta Basin. Questar E&P participated in 103 gross wells in this region in 2003, and had net production of 29 bcfe.

At year-end 2003 Questar E&P had over 100 operated Wasatch well locations yet to drill. However, it expects lower production from the Uinta Basin in 2004. Questar E&P has now drilled over 400 wells in the Uinta Basin since acquiring Shenandoah Energy Inc. (SEI) in mid-2001. Well performance on average has been below what was predicted at the time of the acquisition. The current average expected ultimate recoverable (EUR) reserves for all Wasatch wells drilled to date is approximately 0.8 bcfe, compared to predicted EUR of 1.0 to 1.2 bcfe at the time of the SEI acquisition. Questar E&P attributes disappointing well performance to several factors, including high variability of the extent, quality and thickness of individual reservoirs and gathering system constraints.

In 2003 Questar E&P drilled or participated in six wells around the periphery of its acreage to evaluate the potential of deeper Mesaverde, Blackhawk, and Mancos Formation targets at depths ranging from 9,900 to 13,700 feet. Results to date confirm the presence of gas in the deeper horizons, but initial production rates and projected EUR from the deeper targets have been marginally economic. Questar E&P may drill several additional wells in 2004 to continue evaluation of deep potential on its extensive Uinta Basin leasehold.

Also in 2003 Questar E&P identified multiple oil pools and an updip gas play in the shallow Green River Formation. It continues to believe there is untapped potential in its extensive Uinta Basin leasehold acreage, but the extent and timing of exploitation remains uncertain.

Questar E&P has begun a systematic review of “legacy” properties in the Greater Green River Basin in southwestern Wyoming and northwestern Colorado, where it has 632,000 gross leasehold acres (418,000 net acres). It is evaluating deep potential, downspacing potential, and other play concepts on the flanks of older fields and will likely drill wells to evaluate some of these new opportunities in 2004.

Questar E&P has successfully exploited gas and oil properties in the Midcontinent that were obtained through acquisitions between 1987 and 1998. Total Midcontinent production was 31.9 bcfe in 2003, compared to 32.7 bcfe in 2002.

During 2003 Questar E&P initiated a Hartshorne coalbed methane (CBM) development project in the Arkoma Basin of eastern Oklahoma. It holds an average 71 percent working interest in over 24,000 leasehold acres. The Hartshorne coal has been recognized as a potential CBM play for decades. However, the thin 4- to 6-foot thick coal seam at 2,000 feet was only marginally economic when developed using conventional drilling and completion methods. Questar E&P is using new directional drilling technology to drill horizontal laterals of 1,500 to 2,000 feet while remaining within the thin coal interval. This approach greatly improves individual well recoveries and the overall economics of the play. Average well costs to date have been less than $400,000, with average expected reserves of 0.5 to 0.6 bcfe and average initial production of above 500 Mcfe per day. Based on 160-acre spacing, Questar E&P has a worki ng interest in about 140 locations on its operated leasehold and will continue development in 2004.

E&P, Risk Management

Questar E&P manages risk by focusing primarily on development drilling. In addition, Market Resources may hedge up to 100 percent of its forecasted production from proved developed reserves when commodity prices are attractive. Questar E&P hedges production to lock in acceptable returns to protect cash flows and earnings from a decline in commodity prices. Market Resources also manages market-access risk by building the necessary infrastructure, particularly gathering and processing facilities, to handle production volumes. See Items 7 and 7A. for more information concerning the E&P group's risk-management activities.

Natural gas prices are volatile and subject to seasonal variations. Historically, the demand for natural gas decreases during the summer months and increases during the winter months. In addition to seasonal variations and commodity prices, weather (both in terms of temperatures and moisture) can have dramatic impacts on natural gas prices and on Questar E&P's operations.

Transportation capacity significantly impacts gas prices. The Rocky Mountain region is the fastest growing major producing region in the United States. The region produces more gas volumes than it can use, particularly during the non-heating season of each year. Only about 20 percent of the gas produced in the Rockies is consumed by local markets. Since most production volumes must be transported outside the area, the availability of pipeline capacity is critical. The expansion of the Kern River Pipeline (owned by MidAmerican Energy) in May of 2003, which added an additional 0.9 bcf of daily capacity from the Rocky Mountain area, helped sustain price levels during the summer of 2003. This new expansion, however, is fully subscribed, making it possible that prices will again be depressed during the summer of 2004 as production volumes from Wyoming continue to increase.

E&P, Competition and Customers

Questar E&P 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 growth strategy depends, in part, on its ability to purchase reasonably priced reserves and develop such reserves in a low-cost and efficient manner. During 2003 Questar E&P decreased its lease operating expenses as a result of selling high operating cost properties in 2002 and increasing Pinedale production volumes.

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

E&P, Regulation

Questar E&P's operations are subject to various levels of government controls and regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling and production of wells; maintaining bonding requirements to drill and 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 operations are also subject to various conservation matters, including the regulation of the size of drilling and spacing units, the number of wells that may be drilled in a unit and the unitization or pooling of gas and oil properties.

Most of Questar E&P's leases in the Rocky Mountain area are granted by the federal government and administered by federal agencies. Development of Pinedale leasehold acreage is subject to the terms of winter-drilling restrictions. During the last two years, Questar E&P has been working with federal and state officials in Wyoming to obtain authorization for limited winter drilling activities and has developed innovative measures, such as drilling multiple wells from a single location, to minimize the impact on wildlife and its habitat.

Wexpro, General

Wexpro provides Market Resources with steady growth and predictable earnings through a business model that is unique in the energy industry. Wexpro conducts gas and oil development and production activities on certain producing properties for Questar Gas under the terms of a comprehensive settlement agreement that allows it to recover its costs plus a return on its investment (“Wexpro Agreement”). The terms of the Wexpro Agreement are described in Note 11 in Item 8 of this report.

The gas and associated NGL volumes produced by Wexpro are reflected in Questar Gas’s rates at cost-of-service prices. (“Nonregulated” statistics do not include Wexpro's production and reserves.) Cost-of-service gas, plus the gas attributable to royalty-interest owners, satisfied 49 percent of Questar Gas's system requirements during 2003. The average wellhead cost (net of revenue credits) of Questar Gas's cost-of-service gas in 2003 was $2.59 per dth, which was lower than Questar Gas's average cost for field-purchased gas.

Wexpro, Other

Wexpro’s gas and oil development and production activities are subject to the same type of regulation as Questar E&P. Wexpro is also subject to scrutiny by the Public Service Commissions of Utah and Wyoming and by monitors hired by these entities to review the prudence of Wexpro’s actions and its costs when operating assets for Questar Gas.

Wexpro, under the terms of the Wexpro Agreement, also owns oil-producing properties. The revenues from the sale of crude oil produced from such properties are used to recover operating expenses and to provide Wexpro with a return on its investment. Any net income remaining after recovery of expenses and Wexpro's return on investment is divided between Wexpro (46 percent) and Questar Gas (54 percent).

Gathering, Processing and Marketing, General

Gas Management performs gas gathering and processing activities. Under a contract with Questar Gas, Gas Management gathers cost-of-service volumes produced from properties operated by Wexpro. Gas Management has expanded its scope of gathering and processing activities to serve Questar E&P and other producers. Gas Management is a 50 percent partner in Rendezvous Gas Services (“Rendezvous”), a joint venture that operates gas gathering facilities in western Wyoming. These facilities gather volumes from the Pinedale Anticline and Jonah fields in western Wyoming for delivery to various interstate pipelines that serve the region. Gas Management plans to build a new gathering line from its Blacks Fork processing plant to a connection with the Kern River Pipeline.

Gas Management's processing margins are subject to the price difference between natural gas and NGLs. Gas Management is restructuring some of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. (A “keep-whole” contract insulates producers from NGL- and gas-price risk while a “fee-based” contract eliminates commodity price risk for the processing plant owner.)

Energy Trading conducts energy-marketing activities. Energy Trading combines gas volumes purchased from third parties and equity production (production from affiliates) to build a flexible and reliable portfolio. As a wholesale-marketing entity, Energy Trading concentrates on markets in the Pacific Northwest, Rocky Mountains and Midwest that are close to reserves owned by affiliates or accessible by major pipelines. Energy Trading contracts for firm-transportation capacity on pipelines and firm-storage capacity at Clay Basin (a large baseload-storage facility owned by Questar Pipeline).

Energy Trading uses derivatives as a risk management tool to provide price protection for physical transactions involving equity production and marketing transactions. Energy Trading executes hedges in the form of fixed-price swaps for equity production on behalf of Questar E&P with a variety of contracts of varying duration. Energy Trading does not engage in speculative hedging transactions. See Item 7A and Notes 1 and 6 included in Item 8 of this report for additional information relating to hedging activities.

Energy Trading pays Questar E&P index prices for production volumes on which Questar E&P calculates and pays royalties. Energy Trading then resells such volumes and bears profit and loss risk. In addition to contracting for storage capacity at Clay Basin, Energy Trading also owns a 75 percent interest in and operates the Clear Creek storage facility in southwestern Wyoming. Energy Trading uses owned and leased storage capacity together with firm transportation capacity to take advantage of price differentials and arbitrage opportunities.

Environmental Matters

See Item 3. Legal Proceedings in this report for a discussion of the Company's environmental matters.

Employees

As of December 31, 2003 Market Resources had 535 employees in the United States, compared to 578 at year-end 2002. None of these employees is represented under collective bargaining agreements. The decrease in employees in part reflects the sale of four Company-owned drilling rigs in the first quarter of 2003. The Company also periodically engages independent consulting petroleum engineers and other technical specialists on a fee basis.

ITEM 2.  PROPERTIES.

E&P, 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, 2003. The proved reserve volumes do not include cost-of-service reserves managed and developed by Wexpro for Questar Gas. The reserves were collectively estimated by Ryder Scott Company; H. J. Gruy and Associates, Inc.; and Netherland, Sewell & Associates, Inc., independent petroleum engineers. Market Resources 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.

(1)

Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, using average year-end 2003 prices of $5.57 per Mcf for natural gas and $30.45 per barrel for oil and NGL combined (adjusted for basis, gathering and processing fees, and quality), net of estimated production and development costs (but excluding the effects of general and administrative expenses; debt services; depreciation, depletion and amortization; and income tax expense.

(2)

The standardized measure of discounted net cash flows prepared by the Company represents the present value of estimated future net revenues after income taxes, discounted at 10 percent.

Estimates of proved reserves and future net revenues are made at year-end, using net-to-the-well sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the remaining life of the properties (except to the extent a contract specifically provides for escalation). Year-end prices do not include the effect of hedging. 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 prepared by third-party engineers on behalf of the Company.

Refer to Note 13 included in Item 8 of this report for additional information pertaining to Market Resources' proved reserves as of the end of each of the last three years.

Market Resources will also file estimated reserves as of December 31, 2003 with the Energy Information Administration in the Department of Energy on Form EIA-23. Although Market Resources uses the same technical and economic assumptions when it prepares the EIA-23, the report will differ significantly from the quantities reported herein because the Company is obligated to report reserves for all 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.

Market Resources' nonregulated proved reserves for the years 1999 through 2003 follows:

                Nonregulated Proved Gas and Oil Reserves (bcfe)*

Year

Year-End Reserves

Annual Production

Reserve Life (Years)

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

2003

1,158.7

92.8

12.5

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

E&P, Production

The following table sets forth the net nonregulated production volumes, the average sales prices per Mcf of gas, per barrel of oil and of NGL produced, and the production cost per Mcfe. 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 excludes depreciation, depletion and amortization applicable to capitalized lease acquisition, exploration and development expenditures.

Market Resources’ Productive Wells

The following table summarizes Market Resources' productive wells as of December 31, 2003.  All of these wells are located in the United States.

  Gas

Oil

Total

Gross

3,636

921

4,557

Net

1,686

499

2,185

Although many of Market Resources' 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 produced. Each well completed in more than one producing zone is counted as a single well. At the end of 2003 there were 59 gross wells with multiple completions.

Market Resources also holds 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 Market Resources' gross and net well count.

E&P, Leasehold Acreage

The following table summarizes developed and undeveloped leasehold acreage in which Market Resources owns a working interest as of December 31, 2003. “Undeveloped Acreage” includes leasehold interests that already may have been classified as containing proved undeveloped reserves and unleased mineral-interest acreage owned by the Company. Excluded from the table is acreage in which Market Resources' interest is limited to royalty, overriding royalty and other similar interests.

Leasehold Acreage - December 31, 2003

    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

345

113

3,390

1,240

3,735

1,353

   Colorado

146,505

99,595

199,899

101,495

346,404

201,090

   Idaho

-

-

44,174

10,642

44,174

10,642

   Illinois

172

39

14,267

3,989

14,439

4,028

   Indiana

-

-

269

235

269

235

   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

1,267

1,114

15,703

10,300

   Michigan

169

28

6,400

1,346

6,569

1,374

   Minnesota

-

-

313

104

313

104

   Mississippi

2,862

1,902

1,095

468

3,957

2,370

   Montana

18,349

8,463

308,349

56,497

326,698

64,960

   Nevada

320

280

680

542

1,000

822

   New Mexico

83,873

66,906

35,862

14,610

119,735

81,516

   North Dakota

2,742

458

144,312

21,532

147,054

21,990

   Ohio

-

-

202

43

202

43

   Oklahoma

1,470,260

258,984

48,281

33,421

1,518,541

292,405

   Oregon

-

-

43,868

7,670

43,868

7,670

   South Dakota

-

-

204,398

107,828

204,398

107,828

   Texas

153,646

51,432

55,183

42,423

208,829

93,855

   Utah

82,357

66,135

221,879

116,865

304,236

183,000

   Washington

-

-

26,631

10,149

26,631

10,149

   West Virginia

969

115

-

-

969

115

   Wyoming

229,701

149,430

412,008

246,942

641,709

396,372

      Total

2,239,162

723,713

1,803,440

789,245

4,042,602

1,512,958

(1)

Developed acreage is acreage spaced or assignable to productive wells.

(2)

Undeveloped acreage is leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

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 that event, the lease will remain in effect until production ceases. 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, 2004

     77,872

  51,574

     December 31, 2005

     73,002

  47,483

     December 31, 2006

     84,787

  56,693

     December 31, 2007

     39,786

  36,387

     December 31, 2008 and later

     34,926

  23,595

Market Resources, Drilling Activity

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

              Year Ended December 31,

Productive

Dry

2003

2002

2001

2003

2002

2001

Net Wells Completed

United States

-Exploratory

  3.7

  0.6

 0.4          0.2

1.0          0.4

-Development

132.3

150.9

120.0

  9.6

2.4

  4.3

Canada

             -Exploratory

        -

    0.5

 0.9

     -

       -

  1.9

-Development

    2.3

        -

    2.3

     -

0.4

  0.1

Total

-Exploratory

    3.7

    1.1

 1.3

  0.2

1.0

  2.3

-Development

132.3

153.2

122.3

  9.6

2.8

  4.4

Gross Wells Completed

United States

-Exploratory

  10.0

   2.0

 1.0

  2.0

1.0

  1.0

-Development

282.0

215.0

251.0

19.0

5.0

11.0

Canada

             -Exploratory

        -           1.0

    2.0

     -

   -

  5.0

-Development

        -

    9.0

 9.0

     -

1.0

  1.0

Total

-Exploratory

  10.0

    3.0

 3.0

  2.0

1.0

  6.0

-Development

282.0

224.0

260.0

19.0

6.0

12.0

Gathering, Processing and Marketing

Gas Management owns 1,452 miles of gathering lines located in Utah, Wyoming, Colorado and Oklahoma.  In conjunction with these gathering facilities, Gas Management owns compression facilities, field dehydration and measuring systems. Gas Management is a 50 percent partner in Rendezvous, which owns an additional 156 miles of gathering lines and associated field equipment.

Gas Management owns gas processing plants that have an aggregate daily capacity of 224 MMcf. These plants include the Blacks Fork processing plant in southwestern Wyoming that has a daily capacity of 84 MMcf and the Red Wash processing plant in the Uinta Basin that has a daily capacity of 70 MMcf.

Energy Trading, through a limited liability company in which it has a 75 percent interest, owns and operates the Clear Creek gas storage facility in southwestern Wyoming.

ITEM 3.  LEGAL PROCEEDINGS.

There are various legal proceedings pending against Market Resources 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 two separate lawsuits filed by Jack Grynberg, an independent producer. The first case, United States ex rel. Grynberg v. Questar Corp., Civil No. 99-MD-1604, Consolidated Case MDL No. 1293 (D. Wyo.) 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 quantities on which royalty payments are due the federal government. The Questar defendants have been deposing Grynberg and currently plan to file a motion contending that the court has no jurisdiction over the case because Grynberg cannot satisfy the statutory requirements for jurisdiction.

The second case, Grynberg and L & R Exploration Venture v. Questar Pipeline Co., Civil No. 97CV0471 (D. Wyo.) was originally stayed pending the outcome of issues raised in other cases involving the parties. 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 in this case the plaintiff has added additional claims of antitrust violations 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.

Kansas Cases.  Energy Trading is a named defendant in tandem cases pending in a Kansas district court, Price v. Gas Pipelines, No. 99C30 (Dist. Ct. Kan.) and Price v. El Paso Entities, No. 03 C 23 (Dist. Ct. Kan.). These cases are 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 purported class involves all royalty owners of production from non-federal and non-Indian lands located in Kansas, Wyoming, and Colorado. Energy Trading opposes certification of the class and contends that it does not engage in any measurement activities in Kansas. Affiliates of Energy Trading do engage in measurement activities, but not in Kansas.

Beaver Gas Pipeline System.  Questar E&P is a named defendant in Kaiser-Francis Oil Co. v. Anadarko Petroleum Corp., Case No. CJ-2003-66518 (Dist. Ct. Okla.). This lawsuit was filed by its co-defendant in a prior Oklahoma case, Bridenstine v. Kaiser-Francis Oil Co. The original lawsuit was a class action with allegations of improper royalty payments for wells connected to the Beaver Gas Pipeline System in western Oklahoma. Questar E&P and Anadarko (as the successor to Union Pacific Resources Company) settled the lawsuit in December of 2000 by agreeing to pay a total sum of $22.5 million, of which $16.5 million was allocated to Questar E&P. Kaiser-Francis chose not to settle and had a jury verdict in excess of $50 million (including interest and reflecting a credit for the settlement) entered against it.

In the new lawsuit, Kaiser-Francis claims express and implied indemnity against its former co-defendants and requests payment for the damages assessed against it and for its legal defense costs. Questar E&P has asked the court to dismiss the lawsuit for failure to state a claim, or, at the very least, to transfer the case to the county in which the 2000 settlement agreement was approved and the jury trial was held.

Questar E&P is the named defendant in two other cases involving the Beaver system. In State of Oklahoma, Commissioners of the Land Office v. Kaiser-Francis Oil Company, et. al., No. CJ 2002-94, the state of Oklahoma opted out of the class represented in the Bridenstine case and alleges basically the same claims present in such case, e.g., improper deductions for gathering fees and resulting underpayment of royalties. The Oklahoma Tax Commission, in Oklahoma ex rel. State Tax Commission v. Questar Exploration and Production Co., No. W-2004-10 (Dist. Ct. Okla.), contends that Questar E&P should pay additional production taxes to reflect the settlements involving the Beaver system and another pipeline system formerly owned by Questar E&P.

Bishop.  Wexpro and Questar Gas have been named as defendants in a new case, Bishop v. Questar Gas Co., No. C-04-45R (Wyo. Dist. Ct.). This class-action case involves allegations that the defendants underpaid royalties on cost-of-service volumes produced between July 1, 1989 and December 31, 1995 and failed to properly disclose deductions on royalty checks. In 2002 the same Questar defendants and the plaintiffs settled royalty underpayment claims involving cost-of-service volumes produced in 1996 and subsequent years. See the Company's Form 10-Q Report for the Quarter ended September 30, 2002, Item 1.  Legal Proceedings. This new case was served on March 22, 2004 and has not been certified as a class action. The named Questar defendants will oppose class certification and will vigorously defend against the allegations raised in the new complaint on the basis that no deduction s were taken and therefore none needed to be reported.

Environmental Matters.  Questar E&P has intervened in a lawsuit that was filed by Wyoming environmental groups against the Bureau of Land Management (“BLM”), Wyoming Outdoor Council v. Bennett, Case No. 03-CV50-J (D. Wyo.). The environmental groups claim that the BLM violated federal law and regulatory provisions when it approved Questar E&P's request for an exception that allowed limited drilling to be conducted during the winter of 2002-2003. (Questar E&P obtained another exception for the winter of 2003-2004.) Questar E&P contends that the BLM complied with federal regulations by taking a “hard look” at the environmental effects of granting a limited exception and by posting proper notice before taking such action.

Market Resources subsidiaries are listed as “responsible parties” at other sites involving hazardous wastes. They have also received formal notices of violation or informal inquiries from state environmental agencies and the federal Environmental Protection Agency (the “EPA”). None of these sites is significant to the entity involved. With the possible exception of an enforcement action that the EPA may bring against QEP Uinta Basin, Inc. (a subsidiary of Questar E&P) for violation of air permit requirements for operations on tribal lands in eastern Utah, there is no pending proceeding involving formal or informal notices of violation that includes a penalty of $100,000 or more.

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

The Company, as a wholly-owned subsidiary of a reporting company under the Exchange Act, is entitled to omit the information in this Item.

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 Consolidated Shareholder's Equity and the Notes to Consolidated 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 Exchange Act, as amended, is entitled to omit the information requested in this Item.

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

Questar Market Resources, Inc. and its subsidiaries (the “Company” or “Market Resources”) is a wholly owned subsidiary of Questar Corporation (“Questar”). Market Resources, through its subsidiaries, conducts gas and oil exploration, development and production, gas gathering and processing, wholesale-energy marketing and operates a private gas-storage facility. Questar Exploration and Production (“Questar E&P”), conducts exploration, development and production activities. Wexpro Company (“Wexpro”) operates and develops cost-of-service reserves for an affiliate, Questar Gas. Questar Gas Management (“Gas Management”) gathers and processes natural gas. Questar Energy Trading (“Energy Trading”) markets equity and third-party gas and oil, provides risk-management services and through its interest in Clear Creek Storage Company, LLC, operates an underground gas-storage reservoir. Market Resources uses price hedges to protect earnings and cash flows from adverse commodity-price changes, but does not enter into gas- and oil-hedging contracts for speculative purposes. Following is a summary of Market Resources' financial results and operating information:

Exploration and Production Activities

Market Resources’ 2003 net income benefited from higher prices for natural gas, oil and natural gas liquids. Realized natural gas prices, net to the well, increased 40% year over year compared to 2002. Realized oil and natural gas-liquid prices, net to the well, increased 15% in 2003. A change in accounting for asset-retirement obligations reduced Questar E&P income by $4.6 million in 2003.

Approximately two-thirds of Market Resources' annual nonregulated production is in the Rockies region and one-third in the Midcontinent region. Rockies prices increased 53% in 2003 versus 2002. Rockies prices benefited from the expansion of a regional pipeline in May 2003 which added 0.9 bcf per day of transportation capacity. The Rockies basis differential – measured against the NYMEX benchmark – averaged $1.93 per MMbtu from May 2002 to April 2003 and fell to $0.60 per MMbtu between May and December 2003. In response to lower gas prices in 2002 Questar E&P shut-in 3.3 bcfe of Rockies gas production. Midcontinent realized natural gas prices were 27% higher in 2003 compared with 2002.

The Company has hedged 67.9 bcf of forecasted 2004 natural gas production at $4.02 per Mcf, net to the well. Net-to-the-well prices reflect adjustments for basis, gathering and processing fees, and quality.

Market Resources hedged or presold approximately 70% of nonregulated gas production in 2003 at an average price of $3.38 per Mcf, net to the well. The 2003 hedges resulted in a $43.2 million revenue reduction compared with revenues that would have been realized had the Company not hedged its production. About 53% of nonregulated oil production was hedged or presold at an average price of $21.80 per bbl, net to the well, resulting in an $11.8 million reduction in oil revenues. In 2002 hedging activities added $32.9 million to gas revenues and reduced oil revenues by $7 million. Market Resources hedges gas and oil production when prices are attractive to lock in acceptable returns and cash flow, and to protect against price declines. The Company believes hedging lowers risk and thus lowers cost of capital.

Nonregulated natural gas-equivalent production was 4% lower in 2003 compared to the prior year due to natural decline and sale of noncore producing properties, including the Company’s Canadian subsidiary. Adjusted for property sales, production was 10% higher in 2003 at 92.8 bcfe compared with 84 bcfe in 2002. Overall Rockies production increased 9% year over year. Midcontinent production declined 2% in 2003 due to natural decline and the sale of noncore producing properties in 2002. Following is a table showing production volumes by region:

Market Resources expects to replace natural gas and oil production and continue to grow nonregulated reserves in 2004, primarily through increased development drilling in the Rockies and continued development drilling in the Midcontinent.

Market Resources completed its first full year of a program designed to accelerate the pace of drilling while reducing the environmental impact of its development activities on the Pinedale Anticline in western Wyoming. During 2003 Market Resources drilled and completed 25 gross (17.1 net) new wells at Pinedale. In addition, two wells were drilled to intermediate-casing points, and one well was drilling at year end. Market Resources’ net nonregulated Pinedale production totaled 15.2 bcfe for 2003 compared to 8.6 bcfe in 2002 a 76% increase.

During the winter of 2002-2003 Market Resources conducted long-term production tests on six wells that were drilled to test the deeper Mesaverde Formation at Pinedale. The Mesaverde immediately underlies the main Lance Formation pay interval. Based on encouraging test results, all 2003 Pinedale wells were drilled and completed in both the Lance and Mesaverde pay intervals. 2003 drilling results demonstrate the widespread productive potential of the Mesaverde on the Company’s Pinedale acreage.

Also during 2003 Market Resources demonstrated that pad drilling at Pinedale is technically feasible and commercially viable at current commodity prices. By directionally drilling up to 16 development wells from each surface location, Market Resources can develop this world-class gas accumulation while minimizing the surface disturbance and environmental impact on critical mule-deer winter rangeland. With year-round drilling, Market Resources projects that it could drill all remaining wells on its Pinedale acreage with only nine new drilling pads. The Company is working with various stakeholders on a five-year study to assess the impact of winter drilling on wildlife.

In 2004 Market Resources will evaluate the deeper potential of the Pinedale acreage. To date, the Company has only drilled down to depths of about 14,500 feet on the Pinedale structure. A number of potentially productive deeper formations at depths of up to 19,500 feet remain untested. While there are examples of prolific production from these formations and depths elsewhere in the Rockies, the deeper potential on the Company’s acreage has not been evaluated. Only one well, 20 miles to the south of Market Resources’ acreage, has been drilled below the Mesaverde Formation on the Pinedale Anticline. Drilled in 1972, the well encountered a series of potential reservoir horizons but had mechanical problems and was never tested conclusively.

Production from Questar E&P’s Uinta Basin properties in eastern Utah grew 8% to 29 bcfe in 2003. Production data indicates well performance in some areas is falling significantly below projections made at the time the Company acquired Shenandoah Energy (SEI). Current average reserves for all Wasatch Formation wells completed to date is approximately 0.8 bcfe per well compared to predicted reserves of 1.0 to 1.2 bcfe at the time of the acquisition. Factors causing reduced well performance include high variability of the size, quality and thickness of individual reservoirs and difficulties in optimizing the gathering system to handle the highly variable flowing wellhead pressures that exist between different vintage wells. Market Resources continues to adjust its reserve base to reflect performance-related revisions.

Higher sales prices in 2003 resulted in higher production taxes. Lease-operating expenses were lower in the 2003 period after the 2002 sale of higher-cost Canadian and other noncore properties. Depreciation, depletion and amortization rates increased in 2003 due to higher costs and in part due to lower estimated reserves in Questar E&P’s Uinta Basin properties. A comparison of costs for nonregulated production is shown in the table below: 

Nonregulated Gas and Oil Reserves

In 2003 gas and oil reserves increased 4%, after production and sales of producing properties, to 1,159 bcfe. Questar E&P’s nonregulated production-replacement ratio was 149% in 2003 and 26% in 2002. Net reserve additions, revisions, purchases and sales in place totaled 138 bcfe in 2003 and 25 bcfe in 2002. Questar E&P’s five-year average finding cost of nonregulated reserves per Mcfe was $0.84 in 2003 and $0.85 in both 2002 and 2001.

Proved nonregulated reserves by major operating areas at December 31, 2003 follow:

Wexpro Earnings

Wexpro earned $32.6 million in 2003 compared to $30.8 million in 2002 due to increased investment in gas-development wells, higher realized prices for oil, capitalized interest associated with construction, and lower debt expense. Wexpro manages and develops gas reserves on behalf of Questar Gas. Wexpro activities are governed by a long-standing agreement (Wexpro Agreement) with the States of Utah and Wyoming. Pursuant to the Wexpro Agreement, Wexpro produces gas on behalf of Questar Gas, recovers its costs and receives an after-tax return of approximately 19% on its net investment in commercial wells and related facilities – known as the investment base – adjusted for working capital, deferred taxes, and depreciation. Wexpro’s 2003 results included a $563,000 after-tax charge for the cumulative effect of an accounting change for asset-retirement obligations.

Gas Gathering and Processing; Gas and Oil Marketing

Net income from gas gathering and marketing operations increased 18% to $13.0 million in 2003. Gathering volumes increased 11.5 MMdth to 202.5 MMdth in 2003 as the result of increased investment in gathering facilities in the Pinedale area. Gas Management’s December 2002 purchase of the remaining 50% of the Blacks Fork processing plant added $1.9 million to income in 2003. Pre-tax earnings from Gas Management’s 50% interest in Rendezvous Gas Services increased from $2.2 million in 2002 to $4.7 million in 2003. Rendezvous provides gas gathering services for the Pinedale/Jonah producing areas. Energy Trading’s margins – revenues less the costs to purchase gas and oil and transport gas – declined $1.8 million in 2003 due primarily to losses from long-term transportation contracts that were above market rates for much of 2003.

Interest and Other Income

In 2002 Market Resources sold noncore properties resulting in a $43.2 million pretax gain and favorably settled a lawsuit and other contracts resulting in $5.6 million of pretax earnings. Sales of noncore properties generated a $13.9 million pretax gain in 2001.

Debt Expense

Debt expense was 19% lower in 2003 compared with 2002 primarily due to lower debt balances. Market Resources used proceeds from fourth quarter 2002 asset sales and cash flow from operations to reduce debt. Debt expense was 52% higher in 2002 compared with 2001 primarily due to increased debt used to fund the purchase of SEI in July of 2001. The impact of higher debt was partially offset by lower short-term interest rates.

Earnings from Unconsolidated Affiliates

Rendezvous Gas Services' income increased in 2003 due to higher volumes and rates. Gas Management is a 50% owner in Rendezvous, which provides gas-gathering services for the Pinedale/Jonah producing area of western Wyoming. Gas Management’s share of earnings from the Blacks Fork processing plant are included in the 2002 and 2001 results. Gas Management became the sole owner of the Blacks Fork processing plant in the fourth quarter of 2002.

Income Taxes

The effective combined federal, state and foreign income tax rate was 36.3% in 2003, 35.2% in 2002 and 34.9% in 2001. The Section 29 income tax credit associated with production of nonconventional fuels expired December 31, 2002. Section 29 credits were $4.9 million in 2002 and $5 million in 2001.

Cumulative Effect of Changes in Accounting Method

On January 1, 2003 the Company adopted a new accounting rule, Statement of Financial Accounting Standards (SFAS) 143, “Accounting for Asset-Retirement Obligations” and recorded a cumulative effect that reduced net income by $5.1 million. SFAS 143 accretion expense was $2.3 million in 2003.

LIQUIDITY AND CAPITAL RESOURCES

Net cash provided from operating activities increased 3% in 2003 compared with 2002 due to increased to income and noncash adjustments to income. Higher realized prices for gas and oil in 2003 resulted in an increased investment in receivables, inventories and hedging collateral deposits. Net cash provided from operating activities increased in 2002 compared with 2001 primarily due to higher depreciation and deferred income taxes.

Investing Activities

Market Resources increased its investment in the Pinedale Anticline development project in 2003. Market Resources plans to drill and complete 30 wells at Pinedale in 2004 compared to 25 in 2003 and an average of about 15 wells per year in the 2000-2002 periods. In 2003 Market Resources participated in 352 wells (146 net), resulting in 136 net successful gas and oil wells and 10 net dry or abandoned wells. The net drilling success rate was 93% in 2003. There were 39 gross wells in progress at year end. In 2003 Gas Management invested $14.8 million in the Rendezvous partnership.

Capital expenditures for 2002 and 2003 and a forecast for 2004follows:

Financing Activities

Net cash from operations exceeded the sum of net investing activities and dividends by $23.1 million in 2003 and $212.8 million in 2002. Market Resources paid down its revolving debt by $145 million. In 2002 the Company generated more than $158 million of cash through the sale of noncore assets and used the proceeds to repay debt.

Market Resources’ consolidated capital structure consisted of 40% debt and 60% shareholder equity at December 31, 2003. Moody’s and Standard & Poor’s have rated Market Resources senior unsecured debt Baa3 and BBB+, respectively.

Maturing long-term debt and the fair value of hedging contracts at December 31, 2003 resulted in current liabilities in excess of current assets.

The Company has negotiated a new credit facility to replace an existing facility that matures in April 2004. The new facility has terms that are comparable to or better than the maturing facility and extends through March 2009.

Contractual Cash Obligations and Other Commitments

Market Resources enters into a variety of contractual cash obligations and other commitments in the course of ordinary business activities. The following table summarizes the Company's significant contractual cash obligations:

Critical Accounting Policies, Estimates and Assumptions

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. 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

The Company follows the successful-efforts method of accounting for gas- and oil-property acquisitions, exploration, development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs, the costs of carrying unproved property and unsuccessful exploratory-well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred.

The costs of unproved properties are generally combined and amortized over the expected holding period for such properties. Individually significant unproved properties are periodically reviewed for impairment. Net capitalized costs of unproved properties are reclassified as proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.

Capitalized proved-property-acquisition costs are amortized by field using the unit-of-production method based on proved reserves. Capitalized exploratory-well and development costs are amortized similarly by field based on proved-developed reserves. The calculation takes into consideration estimated future equipment dismantlement, surface restoration and property-abandonment costs, net of estimated equipment-salvage values. Other property and equipment is generally depreciated using the straight-line method over estimated useful lives or the unit-of-production method for certain processing plants. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production amortization rate would be significantly affected.

The Company engages independent consultants to prepare estimates of the nonregulated proved 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.

Long-lived assets are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated on a field-by-field basis. If the undiscounted pretax cash flows are less than the carrying value of the asset group, the carrying value is written down to estimated fair value which is determined using discounted future net revenues.

Wexpro Agreement  

Wexpro activities are governed by a long-standing agreement, the Wexpro Agreement, with the states of Utah and Wyoming. Pursuant to this agreement, Wexpro produces gas on behalf of Questar Gas and is reimbursed for incurred costs. In addition, Wexpro receives an after-tax return on its investment in commercial wells and related facilities – known as the investment base – adjusted for working capital, deferred taxes and depreciation. The Wexpro Agreement also sets forth the rights of Questar Gas’s utility operations to share a portion of the profits from Wexpro’s oil-development operations after the recovery of costs and an allowed return. The Wexpro Agreement was approved by the Public Service Commission of Utah and the Public Service Commission of Wyoming in 1981 and affirmed by the Utah Supreme Court in 1983 (See Item 8,

Note 11).

Accounting for Derivatives

The Company uses derivative instruments, typically fixed-price swaps, to hedge against a decline in the average market price 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 energy-derivative instruments as cash-flow hedges as defined in SFAS 133 “Accounting for Derivative Instruments and Hedging Activities” as amended. 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 as 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, oil and NGL revenues, whereby revenue is recognized on all gas, oil and NGL 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. Revenues and prices for gas, oil, and NGL are reported on a “net-to-the-well” basis after adjustments for basis, gathering and processing fees, and quality.

Recent Accounting Developments

The Securities and Exchange Commission has requested that the Financial Accounting Standards Board review the applicability of certain provisions of SFAS 141, “Business Combinations,” and SFAS 142, “Goodwill and Other Intangible Assets.” For a discussion of recent accounting developments, see disclosures in Item 8,

Note 1.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market Resources’ primary market-risk exposures arise from commodity-price changes for natural gas, oil and other hydrocarbons and volatility in interest rates. Energy Trading has long-term contracts for pipeline capacity and is obligated for transportation services with no guarantee that it will be able to recover the full cost of these transportation commitments.

Commodity-Price Risk Management

Market Resources bears the risk associated with commodity-price changes and uses gas- and oil-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 Market Resources-owned gas and oil production and for a portion of gas- and oil-marketing transactions.

Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. Natural gas-and-oil-price hedging support Market Resources’ earnings, rate of return and cash flow targets and protect earnings from downward movements in commodity prices. The volume of hedged production and the mix of derivative instruments are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by Market Resources’ Board of Directors. The Company may to hedge up to 100% of forecast production from proved-developed reserves when prices are attractive. Proved-developed production represents production from existing wells. Market Resources does not enter into derivative arrangements for speculative purposes and does not hedge undeveloped reserves. Hedges are matched to equity gas and oil production, thus qualifying as cash-flow hedges under the accounting provisions of SFAS 133 as amended and interpreted. Gas hedges are structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness.

That portion of hedges no longer deemed effective is immediately recognized in the income statement. The ineffective portion of hedges was not significant in 2003, 2002 and 2001.

As of December 31, 2003 approximately 80% of forecast 2004 gas production is hedged at an average price of $4.02 per Mcf, net to the well. Hedges are more heavily weighted to the Rockies to reduce basis risk and to protect returns on capital. In addition, Market Resources could curtail production if prices drop below levels necessary for profitability.

Market Resources enters into commodity-price hedging arrangements with several banks and energy-trading firms. Generally, the contracts allow some amount of credit before Market Resources is required to deposit collateral for out-of-the-money hedges. In some contracts, the amount of credit allowed before Market Resources must post collateral varies depending on the credit rating assigned to Market Resources’ debt. At Market Resources’ current credit ratings, the credit available from each counterparty ranges between $5 million and $20 million, depending on the agreement. In cases where this arrangement exists, if Market Resources' credit ratings fall below investment grade (BBB- by Standard & Poor’s or Baa3 by Moody’s), counterparty credit generally falls to zero. The Company maintains lines of credit to cover potential collateral calls. Collateral required at December 31, 2003 was $9.1 million.

A summary of Market Resources’ hedging positions for equity production as of February 18, 2004 is shown below. Prices are net to the well. Currently, all hedges are fixed-price swaps with creditworthy counterparties, which allows the Company to achieve a known price for a specific volume of production delivered into a regional sales point, i.e., incorporating a known basis. The swap price is then reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price.   

Market Resources held gas-price hedging contracts covering the price exposure for about 148.1 million dth of gas as of December 31, 2003. At December 31, 2003 all oil-price hedging contracts had expired. Early in 2004 oil-hedging opportunities at attractive prices allowed Market Resources to hedge oil prices covering 733,000 barrels of oil. A year earlier Market Resources’ hedging contracts covered 85.2 million dth of natural gas and 1.1 million barrels of oil. The Company does not hedge the price of natural gas liquids.

A reconciliation of the fair value of hedging contracts for the 12 months ended December 31, 2003 is shown below. The reconciliation incorporates the valuation of financial and physical contracts.

A vintaging of the net fair value of gas-hedging contracts as of December 31, 2003 is shown below. About 99% of all contracts will settle and be reclassified from other comprehensive income in the next 12 months.

Market Resources’ mark-to-market valuation of gas and oil price-hedging contracts plus a sensitivity analysis follows:

Interest-Rate Risk Management

Market Resources had $350 million of fixed rate debt with a fair value of $395.5 million and $385.1 million

at December 31, 2003 and 2002, respectively. The fair value of fixed rate debt is subject to change as interest rates fluctuate. The Company held variable-rate long-term debt at December 31, 2003 and 2002 amounting to $55 million and $200 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 $100,000 based on the balance outstanding at December 31, 2003 and $400,000 for December 31, 2002 balance.

Credit Risk

Market Resources requests credit support and, in some cases, prepayment from companies with unacceptable credit risks. Market Resources' five largest customers are BP Energy Company, Sempra Energy Trading Corporation, Oneok Energy Marketing, Virginia Power Energy, and Coral Energy Resources LP. Transactions with these five companies accounted for 24% of Market Resources revenues in 2003 and were current on their accounts as of the date of this report.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Financial Statements:

Report of Independent Auditors

Consolidated Statements of Income, three years ended December 31, 2003

Consolidated Balance Sheets at December 31, 2003 and 2002

Consolidated Statements of Shareholder’s Equity, three years ended

December 31, 2003

Consolidated Statement of Cash Flows, three years ended December 31, 2003

Notes to Consolidated Financial Statements

Financial Statement Schedules:

For the three years ended December 31, 2003

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. and subsidiaries as of December 31, 2003 and 2002, 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, 2003. 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 and schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Questar Market Resources, Inc. and subsidiaries at December 31, 2003 and 2002, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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.

As discussed in Notes 1 and 2 to the financial statements, Questar Market Resources, Inc. and subsidiaries adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” effective January 1, 2002 and Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003.

Salt Lake City, Utah

February 10, 2004

/s/Ernst & Young LLP

Ernst & Young LLP

QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY

QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

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 “Market Resources”). The Company is a wholly owned subsidiary of Questar Corporation (“Questar”). Market Resources, through its subsidiaries, conducts gas and oil exploration, development and production, gas gathering and processing, wholesale-energy marketing and operates a private gas-storage facility. Questar Exploration and Production (“Questar E&P”), conducts exploration, development and production activities. Wexpro Company (“Wexpro”) operates and develops cost-of-service reserves for an affiliate, Questar Gas. Questar Gas Management (“Gas Managrment”) gathers and processes natural gas. Questar Energy Trading (“Energy Trading”) markets equity and third-party gas and oil, provid es risk-management services and through its interest in Clear Creek Storage Company, LLC, operates an underground gas-storage reservoir. All significant intercompany balances and transactions have been eliminated in consolidation.

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

Use of Estimates:  Under generally accepted accounting principles in the United States, management is required to make estimates and assumptions that affect reported assets, liabilities and contingent liabilities in the financial statements and accompanying notes. Actual results could differ from those estimates.

Revenue Recognition:  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 gas reserves in an underlying property. The Company’s net gas imbalances at December 31, 2003 and 2002 were $2.4 million and $1.8 million, respectively. Revenues and prices for gas and oil are reported “net to the well” in that costs for gathering and processing, oftentimes paid by purchasers of the products, are not included in the reported revenues. Market Resources manages commodity-price risk through the use of natural gas- and oil-price-hedging instruments.

Wexpro Agreement – Oil Income Sharing:  Oil income sharing represents payments made to Questar Gas for its share of the income from oil and natural gas liquids products associated with cost-of-service oil properties pursuant to the terms of the Wexpro Agreement.

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 and cash equivalents consist principally of cash balances held in commercial banks and repurchase agreements with maturities of three months or less. Repurchase agreements are highly liquid investments in overnight securities made through the Company's commercial bank.

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.

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. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production amortization rate would be significantly affected.

Capitalized proved-leasehold costs are depleted using the unit-of-production method based on proved reserves on a field basis. The costs of unproved gas and oil leaseholds are generally combined and amortized over a period that is based on the average holding period for such properties. 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 capitalizes an estimate of the fair value of abandonment costs, less estimated salvage values, and depreciates those costs over the life of the related asset.

Cost-of-service gas and oil operations

The successful-efforts method of accounting is used for “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 11). 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.

Depreciation, depletion and amortization

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. The Company capitalizes an estimate of the fair value of abandonment costs, less estimated salvage values, and depreciates those costs over the life of the related asset.

Average depreciation, depletion and amortization rates used in the 12 months ended December 31 were as follows:

Impairment of Long-Lived Assets:  Proved gas and oil properties are evaluated on a field-by-field basis 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 Standard (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 indicate an impairment 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 impairment is indicated, fair value is calculated using a discounted cash flow approach. Cash flow projections requ ire estimates of future revenues, operating costs, and other factors.

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. The Company conducts annual impairment tests in the fourth quarter. 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, 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.

Capitalized Interest and Allowance for Funds Used During Construction:  When applicable, Market Resources capitalizes interest costs during the construction period of plant and equipment. Under provisions of the Wexpro Agreement, Wexpro capitalizes an allowance for funds used during construction (“AFUDC”) on cost-of-service construction projects. AFUDC amounted to $1.1 million in 2003, $444,000 in 2002 and $703,000 in 2001, 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. 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 Shareholder’s Equity.

Commodity-Price Financial Instruments:  On January 1, 2001 the Company adopted the provisions of SFAS 133 “Accounting for Derivative Instruments and Hedging Activities” as amended and recorded a cumulative effect of this accounting change that decreased other comprehensive income by $79.4 million after tax. The majority of its commodity-price-derivative instruments are structured as cash-flow hedges. A $121 million hedging liability for derivative instruments was recorded as a result of adopting SFAS 133.

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 hedged item.

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 cash settlement. Market Resources accrues for the settlement of contracts in the current month's revenues and cost of sales.

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

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 numerous commercial and industrial enterprises 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. Market Resources requests credit support and, in som e cases, fungible collateral from companies with unacceptable credit risks. The Company has a master netting agreement with some customers that allows the offsetting of receivables and payables in a default situation. The Company is attempting to increase the number of contracts that contain netting provisions. Bad-debt expense amounted to $432,000 in 2003 and $1.2 million for the years ended December 31, 2002 and 2001, respectively. The allowance for bad-debt expenses was $4.1 million and $3.8 million at December 31, 2003 and 2002, 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. Market Resources records tax benefits as they are generated. Deferred income taxes have been provided for temporary 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 result from changes in fair value of qualified energy derivatives. These transactions are not the culmination of the earnings process, but result from periodically adjusting historical balances to fair value. Income or loss is realized when the underlying product is sold.

The balances of accumulated other comprehensive loss, net of income taxes, were $32.6 million and $16.9 million at December 31, 2003 and 2002, respectively.

Business Segments:  Market Resources’ line-of-business disclosures are presented according to senior management’s basis for evaluating performance. Certain intersegment sales include intercompany profit.

Recent Accounting Developments:  The Securities and Exchange Commission has requested that the Financial Accounting Standards Board review the applicability of certain provisions of SFAS 141, “Business Combinations,” and SFAS 142, “Goodwill and Other Intangible Assets,” to companies in the exploration and production business. The issue is whether the provisions of SFAS 141 and SFAS 142 require companies to classify costs associated with mineral rights, including both proved and unproved lease-acquisition costs, as intangible assets on the balance sheet apart from other capitalized gas and oil property costs. As of December 31, 2003 Market Resources' proved and unproved leaseholds had a net book value of $385 million.

Reclassifications:  Certain reclassifications were made to the 2002 and 2001 financial statements to conform with the 2003 presentation.

Note 2 – New Accounting Standard – Accounting for Asset-Retirement Obligations

On January 1, 2003 Market Resources adopted SFAS 143 “Accounting for Asset-Retirement Obligations” and recorded a $5.1 million after tax charge for the cumulative effect of this accounting change. 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 the Company to estimate a fair value of abandonment costs and to capitalize and depreciate those costs over the life of the related assets. The asset-retirement obligation is adjusted to its present value each period through an accretion process using a credit-adjusted risk-free interest rate. Both the accretion expense associated with the liability and the depreciation associated with the capitalized abandonment costs are non-cash expenses.

With the adoption of SFAS 143, Market Resources changed the accounting method for plugging and abandonment costs associated with gas and oil wells and certain other properties. SFAS 143 was applied retroactively to prior years to determine the cumulative effect through December 31, 2002. A portion of the asset-retirement obligation will be recoverable from Questar Gas over 18 years following an amortization schedule or as cash is spent to plug and abandon the gas wells.

Changes in asset-retirement obligations are shown below:

Assuming retroactive application of SFAS 143 as of January 1, 2001 the pro forma effect of applying this new accounting principle would have not materially affected income in 2002 and 2001. The pro forma asset-retirement obligations as of January 1, 2002 were $52.4 million.

Note 3 – Dispositions and Acquisitions

Sale of Canadian Properties

In October of 2002 Market Resources sold its Canadian exploration and production subsidiary, Celsius Energy Resources, Ltd (“CERL”), to EnerMark Inc., a subsidiary of Calgary-based Enerplus Resources Fund and recorded a pretax gain of $US19.7 million. Total consideration received was $US101.6 million. CERL earned net income for the nine months ended September 30, 2002 of $US1.5 million and had total assets of $US80.0 million at September 30, 2002. Market Resources used the proceeds from the sale to repay debt.

Partnership Interests Acquired

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

Note 4 - Investment in Unconsolidated Affiliates

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

Summarized results are listed below:

Note 5 - Debt

Questar makes loans to Market Resources under a short-term borrowing arrangement. Short-term notes payable to Questar totaled $36.5 million at December 31, 2003 with an interest rate of 1.3% and $9.9 million at December 31, 2002 with an interest rate of 1.64%.

At December 31, 2003 Market Resources’ revolving credit facility contained 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 limited payment of dividends to $183 million. The Company has negotiated a new credit facility to replace the existing facility that matured in April 2004.

Cash paid for interest was $28.5 million in 2003, $30 million in 2002 and $22.9 million in 2001.

Note 6 - Financial Instruments and Risk Management

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

The Company used the following methods and assumptions in estimating fair values:

Cash and cash equivalents, short-term debt and variable-rate long-term debt – the carrying amount approximates fair value.

Long-term debt – The fair value of fixed-rate debt is based on the discounted present value of cash flows using the Company's current borrowing rates.

Commodity-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, 2003 was $4.24 per MMbtu, representing the average of contracts with different terms including fixed, various “into-the-pipe” postings and NYMEX references. Commodity-price-hedging contracts were in place for equity gas production and gas-marketing transactions. Deducting transportation and applying heat-value adjustments on the hedges of equity gas as of December 31, 2003 would result in an average price of approximately $4.00 per Mcf, net to the well.

Market Resources held gas-price-hedging contracts covering the price exposure for about 148.1 MMdth of gas as of December 31, 2003. About 99% of those contracts will settle and be reclassified from other comprehensive income in 2004. At December 31, 2003 all oil-price hedging contracts for Market Resources had expired. A year earlier Market Resources’ hedging contracts covered 85.2 MMdth of natural gas and 1.1 MMbbl of oil. Market Resources does not hedge the price of natural gas liquids.

At December 31, 2003 the Company reported a current liability, net of hedging assets, of $49.1 million from hedging activities. Settlement of contracts in 2003 resulted in the reclassification into expense of $15.6 million. The offset to the hedging liability, net of income taxes, was a $15.8 million unrealized loss on hedging activities recorded in other comprehensive loss in the shareholder’s equity section of the consolidated balance sheet. Settlement of contracts resulted in reclassifying $42.4 million from comprehensive loss in 2002 and $68 million from comprehensive income in 2001 to the income statement. The ineffective portion of hedging transactions recognized in earnings was not significant. The fair-value calculation of commodity-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).

Note 7 - Income Taxes

The difference between the statutory federal income tax rate and Market Resources’ effective income tax rate is

explained as follows:

Significant components of the Company's deferred income taxes were as follows:

Cash paid for income taxes amounted to $23.7 million in 2003 and $22.3 million in 2001.  In 2002 Market Resources received an income tax refund amounting to $32 million primarily caused by intangible-drilling costs.

Note 8 - Litigation and Commitments

Litigation

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

Commitments

Energy Trading has contracted for firm-transportation services with various pipelines through 2018 and storage services with Questar Pipeline through 2008. Due to market conditions and competition, it is possible that Energy Trading may not be able to recover the full cost of the transportation commitments. Annual payments and the years covered are as follows:

Market Resources 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 that expires October 31, 2007.  The minimum future payments under the terms of long-term operating leases for the Company's primary office locations for the four years following December 31, 2003 are as follows:

Total rental expense amounted to $2.1 million in 2003, $2.4 million in 2002 and $2.2 million in 2001.  Sublease rental receipts were $111,000 in 2003, $70,000 in 2002 and $294,000 in 2001.

Note 9 - Employee Benefits

Pension Plan:  Most Market Resources 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 semimonthly pay-period interval during the 10 years preceding retirement. Questar is subject and complies with minimum required and maximum allowed annual contribution levels mandated by the Employee Retirement Income Security Act and by the Internal Revenue Code. Subject to the above limitations, Questar intends to fund the qualified retirement plan approximately equal to the yearly expense. Plan assets consist principally of equity securities and corporate and U.S. government debt obligations.  A third-party consultant calculates the pension plan projected benefit obligation.  Pension expense was $1.6 million in 2003, $855,000 in 2002 and $955,000 in 2001.

Market Resources’ portion of plan assets and benefit obligations is can not be determined 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, 2003 and 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, based on an employee's years of service, and generally limited to 170% of the 1992 contribution. Plan assets consist of equity securities and corporate and U.S. government debt obligations. The Company amortizes its transition obligation over a 20-year period, which began in 1992.  A third-party consultant calculates the projected benefit obligation. The cost of postretirement benefits other than pensions was $1.4 million in 2003 and $1.3 million in each of 2002 and 2001.

The Company's portion of plan assets and benefit obligations related to postretirement medical and life insurance benefits can not be determined because the plan assets are not segregated or restricted to meet the Company's obligations. At December 31, 2003 and 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.  Market Resources’ postemployment liability at December 31 was $615,000 in 2003 and $689,000 in 2002.

Employee Investment Plan:  Market Resources participates in Questar's Employee Investment Plan, which allows eligible employees to purchase shares of Questar 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 $1.5 million, $1.4 million and $1.3 million for the years ended December 31, 2003, 2002 and 2001, respectively.

Note 10 - Related Party Transactions

Market Resources receives a significant portion of its revenues from services provided to Questar Gas. The Company received $117.5 million in 2003, $106.6 million in 2002 and $100.5 million in 2001 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 11).

Market Resources pays Questar for certain administrative services. These payments were $8.3 million in 2003, $9.1 million in 2002 and $7.8 million in 2001 and were included in operating and maintenance expenses.  Questar allocates the costs based on each affiliate’s proportional share of revenues, net of gas costs; property, plant and equipment; and payroll.  Management believes that the allocation method is reasonable.

Market Resources’ contracted for transportation and storage services with Questar Pipeline and paid $2.5 million in 2003 and $1.3 million in both 2002 and 2001 for these services. Energy Trading markets liquids extracted from Questar Pipeline’s transmission lines and paid $3.4 million to purchase the liquids in 2003. Questar InfoComm is an affiliated company that provides some information technology and communication services to Market Resources. Market Resources paid Questar InfoComm $1.3 million in 2003 and $1.4 million in 2002 and in 2001.

Market Resources has a lease with Questar for space in an office building located in Salt Lake City, Utah, that expires October 31, 2007.  The building is owned by a third party.  The third party has a lease arrangement with Questar, which in turn sublets office space to affiliated companies. Market Resources paid $761,000 in 2003, $938,000 in 2002 and $945,000 in 2001.

The Company received interest income from affiliated companies of $869,000 in 2003, $700,000 in 2002  and $600,000 in 2001. Market Resources incurred debt expense to affiliated companies of $796,000 in 2003, $2.8 million in 2002 and $3.1 million in 2001.

Note 11 – Wexpro Agreement

Wexpro's operations are subject to the terms of the Wexpro Agreement. The agreement was effective August 1, 1981 and defines Wexpro’s rights and obligations regarding gas reserves owned by Questar Gas. It also defines Questar Gas’s rights to share in the results of other Wexpro operations. The agreement was approved by the Public Service Commission of Utah and the Public Service Commission of Wyoming 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 13.4%. 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 18.4%. 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 gas-development 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 21.4%.

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 13.4%.

Wexpro's investment base, net of depreciation and deferred income taxes, and the yearly average rate of return for 2003 and the previous two years is shown in the table below:

Note 12 – Business Segment Information

Market Resources 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. Market Resources’ 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.

Note 13 – 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 cost-of-service gas and oil properties managed and developed by Wexpro.

Nonregulated Activities

This information pertains to nonregulated gas and oil activities. Cost-of-service activities are presented in a separate section of this note.

Gas and Oil Exploration and Development Activities:  The following information is provided with respect to Market Resources’ gas and oil exploration and development activities, which are located exclusively in the United States. The Company sold its Canadian subsidiary 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 are shown below. Future abandonment costs associated with asset-retirement obligations amounted to $23.5 million at December 31,  2003 and are included in proved properties.

Costs Incurred

Costs incurred in gas and oil exploration and development activities for the years ended December 31 are displayed in the table below.  The costs incurred to develop booked proved undeveloped reserves amounted to $55.3 million, $51.1 million and $20.7 million in 2003, 2002 and 2001, respectively.

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 for the years ended December 31.