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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. 1-8796

QUESTAR CORPORATION

(Exact name of registrant as specified in its charter)

State of Utah

 87-0407509

(State or other jurisdiction of

       (I.R.S. Employer

  incorporation or organization)

     Identification No.)

180 East 100 South, P.O. Box 45433, Salt Lake City, Utah

  84145-0433

(Address of principal executive offices)

     (Zip code)

Registrant's telephone number, including area code:

           (801) 324-5000

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

      Name of each exchange on

Title of each class

  which registered       

Common Stock, Without Par Value, with

      New York Stock Exchange

Common Stock Purchase Rights

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

None

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        

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     Ö      

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)  

Yes   Ö         No        

The aggregate market value of the registrant's common stock, without par value, held by nonaffiliates on February 27, 2004, was $2,955,413,593 (based on the closing price of such stock).*

On February 27, 2004, 83,630,372 shares of the registrant's common stock, without par value, were outstanding.  

Documents Incorporated by Reference.  Portions of the definitive Proxy Statement for the 2004 Annual Meeting of Stockholders are incorporated by reference into Part III.  The sections of the Proxy Statement labeled "Committee Report on Executive Compensation" and "Cumulative Total Shareholder Return" are expressly not incorporated into this document.

*Calculated by excluding all shares held by directors and executive officers of registrant and three non-profit foundations established by Questar Corporation without conceding that all such persons are affiliates purposes of federal securities laws.

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TABLE OF CONTENTS

Heading

PART I

Item 1.

BUSINESS

General

Glossary of Commonly Used Terms

SEC Filings and Website Information

Narrative Description of Business

Market Resources, General

E&P, Growth Strategy

E&P, Risk Management

E&P, Competition and Customers

E&P, Regulation

Wexpro, General

Wexpro, Other

Gathering, Processing and Marketing, General

Regulated Services

Questar Pipeline, (Transmission and Storage), General

Questar Pipeline, Customers, Growth and Competition

Questar Pipeline, Regulation

Questar Gas, (Retail Distribution)

Questar Gas Growth

Questar Gas, Risk Management

Questar Gas, Regulation

Questar Gas, Competition

Other

Environmental Matters

Employees

Executive Officers

Item 2.

PROPERTIES

Questar E&P

Gathering, Processing and Marketing

Questar Pipeline

Questar Gas

Other

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.

SELECTED FINANCIAL DATA

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

Item 9A.

CONTROLS AND PROCEDURES

PART III

Item 10.

DIRECTORS AND EXECUTIVE OFFICERS

OF THE REGISTRANT

Item 11.

EXECUTIVE COMPENSATION

Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL

OWNERS AND MANAGEMENT

Item 13.

CERTAIN RELATIONSHIPS AND RELATED

TRANSACTIONS

Item 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

PART IV

Item 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

SIGNATURES

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," "foreca st," 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 busines s or financial condition of the company; and changes in credit ratings for Questar and/or its subsidiaries.

FORM 10-K

ANNUAL REPORT, 2003

PART I

ITEM 1.  BUSINESS.

General

Registrant Questar Corporation ("Questar" or "the Company") is a natural gas-focused energy company that is involved in the full spectrum of natural gas activities through two groups–Market Resources and Regulated Services.  Market Resources engages in gas and oil development and production; cost-of-service gas development; gas gathering and processing; and wholesale gas and hydrocarbon liquids marketing, risk management, and gas storage.  Regulated Services, through two primary subsidiaries, Questar Pipeline Company ("Questar Pipeline") and Questar Gas Company ("Questar Gas"), conducts interstate gas transmission and storage activities and retail gas distribution services.  

Questar was organized in 1984 and became a publicly held entity when the shareholders of Questar Gas (then known as Mountain Fuel Supply Company) approved a corporate reorganization.  Questar was created to provide organizational and financial flexibility and to achieve a more clearly defined separation of utility and nonutility activities.  Questar is a "holding company," as that term is defined in the Public Utility Holding Company Act of 1935, because Questar Gas is a natural gas utility.  It, however, qualifies for and claims an exemption from provisions of such act applicable to registered holding companies.

As is noted in the following chart, Questar's Market Resources group includes a subholding company, Questar Market Resources, Inc. ("Market Resources"), which owns Wexpro Company ("Wexpro"), Questar Exploration and Production Company ("Questar E&P"), Questar Gas Management Company ("Gas Management") and Questar Energy Trading Company ("Energy Trading").  Questar's Regulated Services group  also includes a subholding entity, Questar Regulated Services Company ("Regulated Services"), which owns Questar Gas, Questar Pipeline and Questar Energy Services, Inc. ("Energy Services").

The Company's limited information technology and communication activities are conducted by Questar InfoComm, Inc. ("Questar InfoComm") which, in turn, owns Consonus, Inc. ("Consonus").

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Financial information concerning the Questar's lines of business, including information relating to the amount of total revenues contributed by any class of similar products or services responsible for 10 percent or more of consolidated revenues, is presented in Note 18 included in Item 8 of this report.

Glossary of Commonly Used Terms

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 equivalents.  Oil volumes are converted to natural gas equivalents 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 oil, gas or natural gas liquids 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 number of wells or acres in which we have 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 of gas.

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 of gas.

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 our 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.

SEC Filings and Website Information

Questar, Market Resources, Questar Gas and Questar Pipeline each file annual, quarterly, and current reports with the Securities and Exchange Commission ("the Commission").  Questar also files proxy statements with the Commission.  Investors can read and copy any materials filed with the Commission at its Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549 and can obtain information about the operations of the Public Reference Room by calling the Commission at 1-800-SEC-0300.  The Commission also maintains a website that contains information filed electronically that can be accessed over the Internet at www.sec.gov.

Financial and other information for Questar can also be accessed at the Company's website at www.questar.com.  Questar's website contains Statements of Responsibility for Board Committees, Corporate Governance Guidelines and its Business Ethics Policy.

Questar and each of its reporting subsidiaries makes available, free of charge, through its website, copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to such reports and all reports filed by officers and directors under Section 16 of the Exchange Act reporting transactions in Questar securities.  Access to these reports is provided as soon as reasonably practicable after such reports are electronically filed with the Commission.

Narrative Description of Business

The Company has three primary segments—Market Resources, Questar Pipeline and Questar Gas.  The following description of each segment's business should be read in conjunction with Item

7.  Management's Discussion and Analysis of Financial Condition and Results of Operation.

Market Resources, General

Questar's Market Resources group is the primary growth driver within Questar.  As shown in the organization chart, Market Resources conducts its operations through several subsidiaries.  Questar E&P acquires and develops gas and oil properties. Wexpro develops cost-of-service reserves for Questar Gas.  Gas Management provides gas gathering and processing services for affiliates and third parties.  Energy Trading markets equity and third-party gas and oil, provides risk-management services, and owns and operates an underground gas-storage reservoir.  

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 geographical 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 the Market Resources' exploration and production (“E&P”) operations.  As of year-end 2003, Market Resources had proved nonregulated reserves (excluding 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 86.2 percent of proved nonregulated reserves (again, excluding cost-of-service 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.

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.

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 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.

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 working 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 will at times 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 Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operation, 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 in May of 2003, which added an additional .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 of its activities on wildlife and the 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. The terms of the settlement agreement are described in Note 17 in Item 8 of this report.  

The gas volumes produced by Wexpro for Questar Gas are reflected in the latter's rates at cost-of-service prices.  (Wexpro's production and reserves statistics are not included in such statistics for any "nonregulated" activities.)  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.  It, however, is also subject to scrutiny by the Utah Division of Public Utilities and the monitors hired by the Division to review the prudence of its actions and its costs when operating assets for Questar Gas.  

Wexpro, under the terms of the settlement 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.  It 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 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 plant owner.)

Energy Trading conducts energy-marketing activities.  It 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.  It 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.  It executes hedges in the form of fixed-price swaps for equity production on behalf of Market Resources with a variety of contracts of varying duration.  Energy Trading does not engage in speculative hedging transactions.  See Notes 1 and 12 included in Item 8 and Item 7A of this report for additional information relating to hedging activities.

Energy Trading pays Questar E&P index prices for production volumes on which the latter entity 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.  It uses owned and leased storage capacity together with firm transportation capacity to take advantage of price differentials and arbitrage opportunities.

Regulated Services

Questar's Regulated Services unit includes Questar Pipeline and Questar Gas.

Questar Pipeline (Transmission and Storage), General

Questar Pipeline is an interstate pipeline company that transports natural gas in the Rocky Mountain states of Utah, Wyoming and Colorado and stores gas volumes in Utah and Wyoming.  As a "natural gas company" under the Natural Gas Act of 1938, Questar Pipeline is regulated by the Federal Energy Regulatory Commission ("FERC") as to rates and charges for storage and transportation of natural gas in interstate commerce, construction of new facilities, extensions or abandonments of service and facilities.  

Questar Pipeline's core transmission system is strategically located in the Rocky Mountain area near large reserves of natural gas.  It is referred to as a "hub and spoke" system, rather than a "long-line" pipeline, because of its physical configuration, multiple connections to other major pipeline systems and access to six major producing areas.  In addition to this core system, Questar Pipeline, through a subsidiary, also owns and operates the Southern Trails Pipeline, a 488-mile line that extends from the Rio Blanco hub in the San Juan Basin to just past the California state line.  

Questar Pipeline operates the Clay Basin storage facility, which is the largest underground storage reservoir in the Rocky Mountain region.  Through a subsidiary, Questar Pipeline also owns gathering lines and a processing plant in Price, Utah that removes carbon dioxide from coalbed-methane gas.

Questar Pipeline, Customers, Growth and Competition

Questar Pipeline's system was originally built to serve retail distribution markets in Utah, and Questar Gas remains Questar Pipeline's largest single transportation customer.  During 2003, Questar Pipeline transported 105.7 MMdth for Questar Gas, compared to 111.7 MMdth in 2002.  Questar Gas has reserved firm-transportation capacity of about 951 MMdth per day on an ongoing basis or about 60 percent of Questar Pipeline's reserved capacity, during the three coldest months of the year.  Questar Pipeline's primary transportation agreement with Questar Gas will not expire until June 30, 2017.  

Given its strategic location and connections to other systems, Questar Pipeline also transported 256.1 MMdth for nonaffiliated customers and delivered such volumes to pipelines owned by Kern River Pipeline, Northwest Pipeline, Colorado Interstate Gas, TransColorado, WIC and other systems.  Questar Pipeline's tariff provides a higher hydrocarbon dew point specification than other systems, which requires less processing by producers before natural gas volumes are delivered to Questar Pipeline's system.  Kern River and Northwest both require lower dew point gas, which means that Questar Pipeline must blend lower dew point processed gas with wet gas and in some instances isolate processed gas for delivery to such lines, which increases its operational costs.

During 2003, Questar Pipeline increased its capacity for deliveries to Kern River by 150 Mdth per day through the Roberson Creek interconnect in southwestern Wyoming.  Questar Pipeline also completed its Tie Line 112 expansion in late 2003.  Questar Gas holds long-term contracts for 52 Mdth per day on this new line, which is expandable to 180 Mdth per day with additional compression.  Tie Line 112 provided critical incremental supplies and operating flexibility during a period of record demand in early 2004.

Rocky Mountain producers and marketers want capacity on transmission systems that move gas to California (Kern River), the Pacific Northwest (Northwest Pipeline) or Midwestern markets (Trailblazer Pipeline, Colorado Interstate Gas).  Questar Pipeline provides access for many producers to the systems.  Some parties, including Gas Management, an affiliate of Questar Pipeline, are building gathering lines that allow producers to make direct connections to such pipeline systems.  Questar Pipeline continues efforts to build or acquire pipelines that transport gas out of the Rocky Mountains.  

Questar Pipeline is unwilling to build significant new projects or expand its existing system without long-term contracts for capacity.  Questar Pipeline has recently announced that it has sufficient market support for an expansion of its southern system in central Utah.  This expansion, which is scheduled to be in service before the 2005-2006 heating season, will add a daily 102 Mdth of capacity, which is fully supported by long-term contracts.  In addition, Questar Pipeline is evaluating customer support for two additional projects.   A potential pipeline project would connect Piceance gas supplies with the Kanda hub in western Wyoming.  Questar Pipeline is also assessing the feasibility of a gas storage project in western Wyoming.  Questar Pipeline will continue to expand its system on an incremental basis to serve the needs of its customers.  

The eastern segment of the Southern Trails line was placed into service in mid-2002.  Marketing constraints and California regulators continue to pose obstacles for Questar Pipeline's efforts to develop the western segment of Southern Trails from the California border to Long Beach, California.  Questar Pipeline continues to be involved in discussions with interested parties to sell or develop the western segment.

Questar Pipeline, Regulation

Questar Pipeline is subject to the jurisdiction of the FERC as to rates and facilities.  Within the last year, it filed necessary tariff provisions to comply with the FERC's segmentation rules and received regulatory permission to file revised tariff sheets to increase its fuel gas costs charged to shippers.  Some shippers are protesting the increased fuel gas costs and are urging the FERC to suspend the tariff sheets pending a hearing or technical conference.  Questar Pipeline also recently filed a request for clarification of Order No. 2004 issued by the FERC in November of 2003.  This order establishes standards of conduct for transmission providers when dealing with "energy affiliates."  Gas Management and Energy Trading are energy affiliates of Questar Pipeline.  Questar Pipeline was actively involved in convincing the FERC to exempt local distr ibution companies such as Questar Gas from being labeled energy affiliates.

Questar Pipeline is also subject to the jurisdiction of the Department of Transportation ("DOT") with respect to safety requirements in the design, construction and operation of its transmission and storage facilities.  Questar Pipeline, in common with Questar Gas, is subject to the additional requirements of the Pipeline Safety Improvement Act of 2002.  This act and rules issued by the DOT require interstate pipelines and local distribution companies to implement a 10-year program of risk analysis, pipeline assessment and remedial repair for transmission pipelines located in high-consequence areas such as populated areas.  Questar Pipeline estimates that its annual cost to comply with the act will be about $1 million.  After the initial 10-year assessment, the pipelines in high-consequence areas must be reassessed every seven years.

Questar Gas (Retail Distribution), General

Questar Gas distributes natural gas as a public utility in Utah, southwestern Wyoming and a small portion of southeastern Idaho.  As of December 31, 2003, it was serving 770,494 sales and transportation customers, a 2.7 percent increase from the 750,128 customers as of year-end 2002.  (Customers are defined in terms of active meters.)  Questar Gas is the only non-municipal gas distribution utility in Utah, where over 96 percent of its customers are located.  Questar Gas has the necessary regulatory approvals granted by the Public Service Commissions of Utah and Wyoming ("PSCU" and "PSCW") and the Public Utility Commission of Idaho to serve these areas.  It also has long-term franchises granted by communities and counties within its service area.

Questar Gas, Growth

Questar Gas's growth is tied to the economic growth of Utah and southwestern Wyoming.  It has over 90 percent of the load for residential space heating and water heating in Utah.  

Questar Gas, Risk Management

Questar Gas faces the same risks as other local distribution companies.  These risks include revenue variations based on seasonal changes in demand, sufficient supplies, sufficient delivery points, and adequate distribution facilities.  Questar Gas's sales to residential and commercial customers are seasonal, with a substantial portion of such sales made during the heating season.  The typical residential customer in Utah (defined as a customer using 115 dth per year) consumes over 77 percent of his total gas requirements in the coldest six months of the year.  Questar Gas, however, has a weather-normalization mechanism for its general service customers.  This mechanism adjusts the non-gas portion of a customer's monthly bill as the actual degree-days in the billing cycle are warmer or colder than normal. This mechanism reduces the sometimes dramatic fluctuations i n any given customer's monthly bill from year to year and reduces fluctuations in Questar Gas's revenues.

Questar Gas minimizes its supply risks by owning natural gas-producing properties.  During 2003, it satisfied 49 percent of its system requirements with the cost-of-service gas and associated royalty-interest volumes produced from such properties.  Wexpro produces the gas from these properties, which is then gathered by Gas Management and transported by Questar Pipeline.  Questar Gas had estimated proved cost-of-service natural gas reserves of 434.4 Bcf as of year-end 2003, compared to 419.9 Bcf a year earlier.

Questar Gas also has a balanced and diversified portfolio of gas supply contracts for volumes produced in the Rocky Mountain states of Wyoming, Colorado, and Utah.  Questar Gas has regulatory approval to include costs associated with hedging activities in its balancing account for pass-through treatment.

Questar Gas has designed its distribution system and annual gas-supply plan to handle design-day demand requirements.  It periodically updates its design-day demand, which is the volume of gas that firm customers could use during extremely cold weather.  For the 2003-04 heating season, Questar Gas used a design-day demand of 1,051 Mdth for firm-sales customers.  

Questar Gas has long-term contracts with Questar Pipeline for transportation capacity and storage capacity at Clay Basin and three peak-day facilities.  It also contracts to take deliveries at several locations on the Kern River Pipeline that runs through Utah.

In third quarter 2004, Questar Gas expects to have its new customer-information system fully operational.  The new system should increase Questar Gas's overall efficiency, provide better information to customers and allow it to reduce labor costs.

Questar Gas's greatest risk, however, is associated with regulation, which is discussed below:

Questar Gas, Regulation

As a public utility, Questar Gas is subject to the jurisdiction of the PSCU and PSCW.  Natural gas sales and transportation services are made under rate schedules approved by the two regulatory commissions.  Questar Gas is authorized to earn a return on equity of 11.2 percent in Utah and 11.83 percent in Wyoming.  Both the PSCU and PSCW permit Questar Gas to recover gas costs through a balancing-account procedure and to reflect gas changes on a periodic, generally semi-annual, basis.  Questar Gas has also received permission from the PSCU and PCSW to reflect specified costs associated with hedging contracts in its gas costs.

At year-end 2002, the PSCU issued an order in Questar Gas's general rate case approving a stipulation that reflected a test year primarily based on November 2002, and changed its accounting for contributions in aid of construction.

On August 1, 2003, the Supreme Court of Utah ("Utah Court") issued an order reversing a decision made by the PSCU in August of 2000 concerning certain processing costs incurred by Questar Gas.  Specifically, the court ruled that the PSCU in 2000 did not comply with its statutory responsibilities and regulatory procedures when approving a stipulation that permitted Questar Gas to reflect $5 million in rates per year to recover certain processing costs.   The court's action forced Questar Gas to record a liability for the amounts collected in rates since June of 1999.

The PSCU subsequently determined to proceed with deliberations in the 1999 case that ended with the stipulation and to address the question whether Questar Gas met its burden of demonstrating that it acted prudently to incur processing costs in its rates in order to enhance the heating value of natural gas volumes delivered to customers.  Before the PSCU could set a schedule of additional hearing and briefs, the Committee of Consumer Services (a state agency that appealed the PSCU's original decision approving the stipulation,) filed a petition for extraordinary relief with the Utah Court.  Questar Gas, The PSCU, and the Division of Public Utilities (another state agency) have filed briefs opposing the Committee's request.  The Utah Court has calendared March 22, 2004, to consider the Committee's petition.

Questar Gas has significant relationships with affiliates that have allowed it to lower its costs and improve its efficiency.  These affiliate relationships, however, are subject to increased scrutiny by regulatory commissions for evidence of subsidization and above-market payments.

At the current time, Questar Gas is reviewing the need to file a general rate case in Utah in 2004.

Questar Gas is also subject to the requirements imposed by the Pipeline Safety Improvement Act of 2002, which is administered by the DOT.  The act requires Questar to develop an integrity-management plan and assess the integrity of its high-pressure lines in "high consequence" areas on a recurring basis.  Questar Gas estimates that it may be required to spend $4 to $5 million per year to comply with the new requirements.

Questar Gas, Competition

Questar Gas is a public utility and currently has no direct competition from other distributors of natural gas for residential and commercial customers.  It has historically enjoyed a favorable price comparison with other energy sources used by residential and commercial customers except coal and occasionally fuel oil.  It provides transportation service to industrial customers that can buy volumes of gas directly from others and have such volumes transported at aggregate prices lower than Questar Gas's sales rates.  Questar Gas makes very low margins on this transportation service, but could lose customers to Kern River.

Other

Questar's "other" operations include information technology and communication services (Questar InfoComm); web-hosting and data centers (Consonus); commercial real estate management (Interstate Land); and well-head gas analysis and automation, field compression and engine maintenance (Energy Services).  Questar is refocusing attention on primary business units and has no plans to enlarge the scope of these activities.  The Company recently announced a reorganization of its information technology services to eliminate duplication and increase efficiency that will result in consolidation of base services within the parent and integrate other services in the business units.  Consonus has never fulfilled its business purpose and has significantly retrenched its operations.  Interstate Land is selling its primary parcels of commercial real estate and will be merged with another Questar entity.

Environmental Matters

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

Employees

At year-end 2003, the Company had 2,173 employees, including 1,368 in the Regulated Services group, 535 in the Market Resources group and 270 in corporate and other areas.

Executive Officers

The following individuals are serving as executive officers of the Company:

Primary Positions Held with the Company

Name

and Affiliates, Other Business Experience

Keith O. Rattie

50

Chairman (May 2003); President (February 2001); Chief Executive Officer (May 2002); Director (February 2001); Chief Operating Officer (February 2001 to May 2002); Director, most affiliates (February 2001); and Senior Vice President of the Coastal Corporation (from 1997 to January 2001).

Charles B. Stanley

45

President, Chief Executive Officer and Director, Market Resources and Market Resources subsidiaries (November 2002); Executive Vice President and Chief Operating Officer, Market Resources and Market Resources subsidiaries (February 2002 to November 2002); Executive Vice President and Director, Questar (November 2002); Senior Vice President, Questar (February 2002 to November 2002); President and Chief Executive Officer and Director, Coastal Gas International Co. (1995 to 2000); President and Chief Executive Officer of El Paso Oil and Gas Canada, Inc. (2000 to January 2002).  

Alan K. Allred

53

President and Chief Executive Officer and Director, Regulated Services, Questar Gas and Questar Pipeline (May 2003); Executive Vice President, Questar (May 2003); Executive Vice President and Chief Operating Officer, Regulated Services, Questar Gas and Questar Pipeline (November 2002 to May 2003); Senior Vice President, Regulated Services, Questar Gas and Questar Pipeline (March 2002 to November 2002); Vice President, Business Development, Regulated Services, Questar Gas and Questar Pipeline (November 2000 to March 2002); Manager, Regulatory Affairs, Questar Gas and Questar Pipeline (October 1997 to November 2000); Director, Wexpro (May 2003).

S. E. Parks

52

Senior Vice President and Chief Financial Officer (March 2001); Treasurer (May 1984 to March 2004); Vice President (February 1990 to March 2001); Vice President, Treasurer, and Chief Financial Officer all affiliates except Energy Trading and Gas Management (at various dates beginning in May 1984); Director, Questar E&P (May 1996).

Connie C. Holbrook

57

Senior Vice President (March 2001); Vice President (October 1984 to March 2001); Corporate Secretary (October 1984); General Counsel (April 1999); Corporate Secretary, Questar Gas and other affiliates except Energy Trading and Gas Management (at various dates begin­ning in March 1982).  

Glenn H. Robinson

53

President, Chief Executive Officer and Director, Questar InfoComm (August 2000); Vice President and Chief Information Officer, Questar (August 2000); Vice President and Controller, Regulated Services (January 1999 to August 2000), Questar Gas (April 1991 to August 2000), and Questar Pipeline (September 1996 to August 2000).

Brent L. Adamson

52

Vice President, Ethics, Compliance and Audit (March 2002); Director, Audit (August 1982 to March 2002); Compliance Officer (March 1995 to March 2002).

There is no "family relationship" between any of the listed officers or between any of them and the Company's directors.  The executive officers serve at the pleasure of the Board of Directors. There is no arrangement or understanding under which the officers were selected.

Item 2.  Properties.

Questar 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, 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 represent 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 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.  

Reference should be made to Note 20 included in Item 8 of this report for additional information pertaining to the Questar's proved reserves as of the end of each of the last three years.

Market Resources will 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, it 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.

The following charts illustrate Market Resources' reserve statistics for the years ended December 31, 1999 through 2003:

                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.

Production.   The following table sets forth the net production volumes, the average sales prices per Mcf of gas, per barrel of oil and of NGL produced, and the production cost per Mcfe for the years ended December 31, 2003, 2002, and 2001, respectively.  Production costs include direct lifting costs (labor, repairs and maintenance, materials, supplies and workovers), and the costs of administration of production offices, insurance and property and severance taxes, but is exclusive of depreciation and depletion applicable to capitalized lease acquisitions, exploration and development expenditures.

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

Productive Wells

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.

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 (i) leasehold interests that already may have been classified as containing proved undeveloped reserves; and (ii) unleased mineral-interest acreage owned by the Company.  Excluded from the table is acreage in which 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

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 processing plants that have an aggregate daily capacity of 224 MMcf.  These plants include the Blacks Fork Plant in southwestern Wyoming that has a daily capacity of 84 MMcf and the Red Wash 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.

Questar Pipeline

Questar Pipeline has a maximum capacity of 1,933 Mdth per day and firm-capacity commitments of 1,655 Mdth per day.  Questar Pipeline's transmission system includes 2,483 miles of transmission lines that interconnect with other pipelines.  Its core system includes two segments, often referred to as the northern system and southern system.  The northern system extends from northwestern Colorado through southwestern Wyoming into northern Utah, while the southern system extends from western Colorado to Elberta, Utah.  The transmission mileage figure includes lines at storage fields and tap lines used to serve Questar Gas, the 488 miles of the Southern Trails system in service that is owned by a subsidiary and the 88 miles of Overthrust Pipeline owned by subsidiaries.  The maximum daily capacity figures for Southern Trails and Overthrust are 899 Mdth and 88 Mdth, respec tively.  Questar Pipeline's system ranges in size from lines that are less than four inches in diameter to the Overthrust line that is 36 inches in diameter.  Through a subsidiary, Questar Pipeline also owns and operates 210 miles comprising the western segment of the Southern Trails system.  Questar Pipeline has major compression sites, including a complex near Rock Springs, Wyoming, that compresses gas volumes from the transmission system for delivery to other pipelines, including systems that move gas volumes east.

Questar Pipeline also owns the Clay Basin storage facility in northeastern Utah, which has a capacity of 117.5 Bcf, including 53.5 Bcf of working gas, and several smaller storage aquifers in eastern Utah.  Through a subsidiary, Questar Pipeline owns a processing plant in Price, Utah, with a daily capacity of 140 MMcf and related gathering lines.

Questar Gas

Questar Gas distributes gas to customers in the major populated area of Utah, commonly referred to as the Wasatch Front, in which the metropolitan Salt Lake area, Provo, Ogden, and Logan are located.  It also serves customers throughout the state, including the cities of Price, Roosevelt, Vernal, Moab, Monticello, Fillmore, Cedar City and St. George.  Questar Gas supplies natural gas to the southwestern Wyoming communities of Rock Springs, Green River, Evanston, Kemmerer and Diamondville and the southeastern Idaho community of Preston.  To supply these communities Questar Gas owns and operates distribution systems and has a total of 23,323 miles of street mains, service lines and interconnecting pipelines.    Questar Gas has a major operations center located in Salt Lake City, Utah, and has operations centers, field offices and service center facilities throug h other parts of its service area.

Other

Questar leases a 255,000 square-foot facility in downtown Salt Lake City, Utah that serves as its corporate headquarters.  Through subsidiaries, it also owns commercial real estate and two secure data centers in metropolitan Salt Lake.

ITEM 3.  LEGAL PROCEEDINGS.

There are various legal proceedings pending against the Company 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.  Questar Gas's processing cost case is discussed under Item 1.  Business, "Questar Gas, Regulation" and in Note 2 to the Notes to Consolidated Financial Statements of Item 8 in this report.  Other significant cases are discussed below.

Grynberg.  Questar defendants 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 fo r 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, and has 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 Ene rgy 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 ex. rel. Commissioners of Land Office, Case No. CJ-2002-94 (Dist. Ct. Okla.) the Oklahoma Land Office, which opted out of the class represented in the Bridenstine case, basically alleges the same claims present in such case, e.g., improper deductions for gathering fees and resulting underpayment of royalties.  The Oklahoma Tax Commission, in State of 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.

Data Center Incident.  Safeway, Inc., a tenant in a data center owned and operated by Consonus, has a pending lawsuit against Consonus claiming that it suffered irreparable damage when its computer system was rendered unfit as a result of an accident that occurred at the center in February of 2002.  The case, Safeway, Inc. v. Consonus, Inc., Civil No. 2:02CV1216DS (D. Utah) is pending in Utah's federal district court.  Safeway claims that Consonus breached its contract to provide a secure facility and was negligent with respect to hiring and monitoring the activities of other named parties responsible for manufacturing the suppression equipment, designing the center, building the center and performing operations at the facility.  The total amount of the claimed damages is in excess of $12 million.  

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

Environmental Matters.  Questar E&P has intervened in a lawsuit that was filed by Wyoming environmental groups against the Bureau of Land Management, 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 2002-03.  (Questar E&P obtained another exception for the winter of 2003-04.)  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.

Questar 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 Questar entity involved.  With the possible exception of an enforcement action that the EPA may bring against QEP Uinta Basin (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.

Wasatch Chemical.  The Company continues to monitor the Wasatch Chemical property in Salt Lake City, which is still included on the national priorities list, commonly known as the "Superfund" list.  The Wasatch Chemical property was the location of chemical mixing operations and is the subject of a 1992 consent order.  Questar has conducted the necessary soil remediation and groundwater remediation activities.

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

The Company did not submit any matters to a vote of stockholders during the last quarter of 2003.

PART II

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

Information concerning the market for the common equity of the Company and the dividends paid on such stock is located in Note 10 of the Notes to Consolidated Financial Statements under Item 8.  As of March 5, 2004, Questar had 10,542 shareholders of record and estimates that it had an additional 30,000-35,000 beneficial holders.

Table_of_Contents

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

SUMMARY

Questar reported a 12% increase in net income to $173.6 million for 2003 compared with earnings of $155.6 million for 2002 due primarily to a 40% increase in realized prices for nonregulated natural gas production. Following is a year-to-year comparison of net income by line of business:

Questar Market Resources (Market Resources) net income grew 18% in 2003 over 2002 due to higher realized prices for natural gas, oil, and natural gas liquids and increased investment in gas gathering in Wyoming.   Nonregulated gas and oil production totaled 92.8 Bcfe) in 2003 compared with 96.3 Bcfe in 2002.  Market Resources’ 2002 net income reflected a $26.8 million after-tax gain from noncore-asset sales, including a Canadian exploration and production subsidiary. Production in 2002, adjusted for asset sales, amounted to 84 Bcfe.

Net income for Questar Pipeline – which conducts interstate natural gas transmission and storage – declined in 2003 compared with 2002. Increased operating expenses and lower capitalized costs for construction projects offset a 7% increase in transportation volumes and a 10% growth in revenues. Pipeline-expansion projects in recent years contributed to an increase in firm-gas transportation in 2003 compared with 2002.  

Questar Gas – a retail natural gas-distribution utility – incurred a 38% drop in net income in 2003 compared with the prior-year earnings due to a $24.9 million pretax rate-refund liability, which was recorded following an adverse Utah State Supreme Court order. The court reversed an earlier decision of the Public Service Commission of Utah (PSCU) that allowed partial recovery of gas-processing costs incurred by Questar Gas from June 1999 forward. The nongas margin (revenues less gas costs) was higher and operating expenses, before the liability, were lower in 2003 compared to 2002. Questar Gas served 770,494 customers at year-end 2003, a 2.7% year-to-year growth rate.

Corporate and Other Operations reported lower income in 2003 – before a 2002 change in the method of accounting for goodwill – due to a decrease in revenues from data-processing and data-hosting businesses.  Under a new accounting rule adopted in the first quarter of 2002, goodwill related to the data-hosting business was determined to be impaired and written off.

Questar implemented an accounting change in 2003 to comply with a new accounting standard for recognizing asset-retirement obligations, reducing net income by $5.6 million or $.07 per share.  The new accounting standard requires companies to anticipate the cost of retiring certain long-lived assets when the assets are placed into service.

RESULTS OF OPERATION

Market Resources

Market Resources and subsidiaries acquire and develop gas and oil properties, develop cost-of-service reserves for an affiliated company, Questar Gas, provide gas-gathering and processing services, market equity and third-party gas and oil, provide risk-management services, and own and operate an underground gas-storage reservoir. Market Resources uses price hedges to protect earnings and cash flows from adverse commodity-price changes. Market Resources 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 Exploration & Production income by $4.6 million in 2003.

Two-thirds of Market Resources' annual nonregulated production is in the Rockies region.  Rockies prices increased 53% in 2003 versus 2002. Rockies prices benefited from the expansion of a regional pipeline in May 2003, which added .9 billion cubic feet 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 $.60 per MMBtu between May and December 2003. In response to lower gas prices in 2002 the company shut-in 3.3 Bcfe of Rockies gas production. Midcontinent realized natural gas prices were 27% higher in 2003 compared with 2002.  

Market Resources capitalized on recent higher natural gas prices to hedge a significant potion of its expected 2004 production. 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 regional 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 barrel (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.

Natural gas-equivalent production was 4% lower in 2003 compared to the prior year due to sale of  noncore producing properties, including the company’s Canadian subsidiary, in 2002. Production was 10% higher in 2003 at 92.8 Bcfe compared with 2002 production, adjusted for property sales, of 84 Bcfe. 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 production and grow proved reserves in 2004, primarily through increased development drilling in the Rocky Mountain region, and continued development drilling in the Midcontinent region.

Market Resources completed its first full year of a program designed to drill more wells per year 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 produced six Pinedale wells to the deeper Mesaverde Formation to assess its potential. Based on the wells’ encouraging production performance, all 2003 Pinedale wells were drilled to the Mesaverde. The success of the 25 wells drilled in 2003 demonstrate the widespread productive potential of the Mesaverde.

Also during 2003, Market Resources demonstrated that pad drilling is a technically and commercially feasible option for full development of the Pinedale Anticline. 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.

Production from Market Resources’ Uinta Basin properties 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 age wells. Market Resources continues to adjust its reserve base to reflect performance-related revisions.

Higher realized 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 lower reserves estimated in the company’s Uinta Basin properties in eastern Utah.  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. Market Resources' 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. Market Resources’ five-year average finding cost of nonregulated reserves per Mcfe was $.84 in 2003 and $.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 this agreement, Wexpro produces gas on behalf of Questar Gas and is reimbursed for incurred costs. In addition, Wexpro 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-retireme nt 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 (one dth is equivalent to one Mcf). Market Resources’ December 2002 purchase of the remaining 50% of the Blacks Fork plant added $1.9 million to income in 2003. Pre-tax earnings from Market Resources’ 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. Marketing 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 out of the money for much of 2003.

Natural Gas Transmission

Questar Pipeline and subsidiaries (Questar Pipeline) conduct interstate natural gas transmission, storage, processing and gathering operations. Following is a summary of financial results and operating information:

Revenues

Natural gas-transmission revenues grew 10% in 2003 compared with 2002 and 14% in 2002 compared with 2001.  Following is a summary of major changes in Questar Pipeline’s revenues:

Questar Pipeline expanded its transportation system in response to growing regional natural gas production and transportation demand. Questar Pipeline added new transportation contracts in 2003 for deliveries to the Kern River Pipeline (owned by MidAmerican Energy) at Roberson Creek and for increased deliveries to Questar Gas customers in northern Utah. The increase in 2002 contracts shown in the above table resulted from the November 2001 start up of Main Line 104. Main Line 104 interconnects with the Kern River Pipeline in central Utah and the Questar Gas system at Payson, Utah.

Questar Pipeline began service in June 2002 on the eastern segment of the Southern Trails Pipeline, which extends from New Mexico’s San Juan basin into California.

Questar Pipeline’s transportation system is nearly fully subscribed. As of December 31, 2003, Questar Pipeline had firm-transportation contracts of 1,655,000 dth per day compared to 1,543,000 dth per day a year earlier, a 7% year-on-year increase. Both years included 80,000 dth per day capacity on the eastern segment of Southern Trails. These contracts have varying terms and lengths. Questar Gas is Questar Pipeline’s largest transportation customer with contracts for 951,000 dth per day, including 50,000 dth per day for winter-peaking service. The majority of Questar Gas’s transportation contracts extend to 2017.

Questar Pipeline’s primary storage facility is Clay Basin in eastern Utah. This facility is 100% subscribed under long-term contracts. Questar Gas has contracted for 62% of firm-storage capacity at Clay Basin for terms extending from 2008 to 2019.

Questar Pipeline subsidiary Questar Transportation Services owns a processing plant near Price, Utah that was built in 1999 to process gas on behalf of Questar Gas. Questar Gas has contracted for 100% of the plant’s firm capacity and pays the cost of service for operating the plant. The net book value of the plant was approximately $15.4 million as of December 31, 2003.

Operating Expenses

Operating and maintenance expenses increased 7% in 2003 over 2002 following a 5% increase in 2002 over 2001. Higher expenses resulted from the startup of operations on the eastern segment of Southern Trails in June 2002. Reduced construction activity and related capitalization of labor costs resulted in higher operating expenses in 2003.  In addition, employee benefits, insurance and pipeline-inspection costs were higher in 2003. Legal expenses were higher in 2002 than 2003 because of the TransColorado Pipeline litigation described below.

Depreciation and property-tax expense increased in 2003, reflecting increased pipeline investment.  Capitalized financing costs related to construction were significantly lower in 2003.

TransColorado Litigation

Questar TransColorado, a Questar Pipeline subsidiary, sold its 50% interest in the TransColorado Pipeline  in 2002 following successful resolution of a protracted legal dispute.

Natural Gas Distribution

Questar Gas conducts natural gas-distribution operations in Utah, part of southwestern Wyoming and part of southeastern Idaho. Following is a summary of financial results and operating information:

Revenues less cost of natural gas sold (margin)

Questar Gas's margin increased by 1% in 2003 compared with 2002 and 10% in 2002 compared with 2001.  Following is a summary of major changes in Questar Gas's margin:

Effective December 30, 2002, the PSCU approved an $11.2 million general-rate increase and an 11.2% allowed return on equity. The PSCU based the increase on November 2002 rate base, operating costs and usage per customer.

At year-end 2003 Questar Gas was serving 770,484 customers.  Customers growth remained above national averages at 2.7% in 2003, 2.5% in 2002 and 3.9% in 2001.  Housing construction in Utah remained strong, driven by low mortgage-interest rates. Usage per general-service customer, adjusted for normal temperatures, increased 1% in 2003 compared with declines of 2% in 2002 and 5% in 2001. The company believes that usage per customer will decline in 2004 as consumers respond to higher natural gas prices.

Weather, as measured in degree days, was 7% warmer than normal in 2003 compared with 8% colder than normal in 2002. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations. However, weather was significantly warmer than normal during September and October 2003, and the company did not fully recover nongas-related costs during the period. This reduced the margin by approximately $1.9 million.

Questar Gas’s 2002 results included $3.8 million of recovery of previously denied 1999 gas-processing costs. The PSCU’s 2002 order allowing the recovery of gas-processing costs is part of a continuing dispute, discussed below.

The company’s 2002 results also included revenues of $5.6 million due to upfront contributions from customers in addition to the amount included in general rates. Accounting for customer contributions changed beginning in 2003 as a result of the 2002 Utah general rate case. Customer contributions are now recorded as a reduction of investment instead of revenues.

Beginning in 2002, the gas-cost portion of bad debts was recovered from customers through the purchased-gas-adjustment account, increasing the 2002 margin by $3.8 million. A decline in bad debts during 2003 reduced the margin by $1.5 million.

Industrial deliveries declined 16% in 2003 following a 12% decline in 2002. Lower power-generation requirements caused 2003 industrial volumes to drop below 2002 levels. The 2002 decline from 2001 was due to lower volumes used in the manufacturing and power-generation sectors.

Operating Expenses

Operating and maintenance expenses declined 5% in 2003 compared with 2002 due to lower information- technology and bad-debt expenses partially offset by higher labor and labor-overhead costs. Operating and maintenance expenses increased 2% in 2002 over 2001 primarily because of higher bad-debt expense.

The Utah Supreme Court issued an order in August 2003 reversing PSCU decisions in 2000 and 2002. The PSCU in August 2000 permitted Questar Gas to collect $5 million per year to recover a portion of the costs of processing certain gas volumes. The processing enables low-Btu gas entering Questar Gas’s system to burn safely and efficiently. In August 2002, the PSCU allowed an additional $3.8 million of recovery from a previous period. As a result of the 2003 Utah Supreme Court order, Questar Gas recorded a $24.9 million before-tax liability in 2003. The liability reflects a potential refund of gas processing costs collected in rates from June of 1999 through December of 2003 plus interest. To protect customer safety, the company must continue to operate the plant.  Therefore, the company believes past and future costs of gas processing are recoverable in rates.  The company expects to resolve this d ispute in 2004.

Depreciation expense increased 1% in 2003 over 2002 after increasing 14% in 2002 over 2001. The 2002 increase was a result of capital expenditures, primarily for information systems.

Corporate and Other Operations

This reporting segment includes noncore investments in information-technology related businesses,  unregulated energy services and corporate activities.

Revenues

Revenues decreased 4% in 2003 compared with 2002 with the company’s exit from the equipment-resale business. Gross margin on products and services sold amounted to $3.1 million in 2003, $2.5 million in 2002 and $5.4 million in 2001. In addition, pricing for intercompany information-technology services was restructured at reduced rates.

Operating expenses

Operating and maintenance expenses increased 2% in 2003 compared with 2002 primarily in response to higher rent charges.

In mid-year 2003, the company acquired the minority-shareholder interests of Consonus, the data-center hosting business, which became a wholly owned subsidiary of Questar InfoComm.

Consolidated Operating Results After Operating Income

Interest and Other Income

Gains from sales of properties and securities and capitalization of construction-financing costs accounted for the high levels of interest and other income in 2002 and 2001 compared with 2003. Details of interest and other income are below:

Earnings of Unconsolidated Affiliates

Rendezvous Gas Services' income increased in 2003 due to higher volumes and rates. A Market Resources subsidiary is a 50% owner in Rendezvous, which provides gas-gathering services for the Pinedale/Jonah producing area of western Wyoming. The company's share of earnings from TransColorado, Overthrust and Blacks Fork is included in the 2002 and 2001 results. The company sold its TransColorado Pipeline interest in 2002. Also, the company became sole owner of Overthrust Pipeline and the Blacks Fork processing plant in the fourth quarter of 2002.

Debt Expense

Lower debt balances and variable-interest rates resulted in lower debt expense in 2003 compared with 2002. In 2002, the Company applied approximately $250 million from asset sales to repay debt that was used to finance a mid-2001 acquisition of gas and oil reserves and related facilities. In addition, Questar Gas replaced higher-cost fixed-rate debt with lower-cost fixed-rate debt in 2003.

Income Taxes

The effective combined federal, state and foreign income tax rate was 36.4% in 2003, 34.8% in 2002 and 35.8% in 2001. The Section 29 income tax credit associated with production of nonconventional fuels expired December 31, 2002. The nonconventional-fuel credits amounted to $6.6 million in 2002 and $6.8 million in 2001.

Cumulative Effect of Changes in Accounting Methods

On January 1, 2003, the Company adopted a new accounting rule, SFAS 143, "Accounting for Asset Retirement Obligations" and recorded a cumulative effect that reduced net income by $5.6 million, or $.07 per diluted common share. Accretion expense associated with SFAS 143 amounted to $2.3 million in 2003. A year earlier, the Company adopted SFAS 142, "Goodwill and Other Intangible Assets," that resulted in impairment of the goodwill acquired by Consonus. Consonus wrote off $17.3 million of goodwill, of which $15.3 million, or $.19 per diluted common share, was Questar InfoComm's share, and reported as a cumulative effect of a change in accounting for goodwill. The remaining $2.0 million was attributed to minority shareholders.

LIQUIDITY AND CAPITAL RESOURCES

Operating Activities

Net cash provided from operating activities decreased 5% in 2003 compared with 2002 due primarily to changes in operating assets and liabilities. Higher gas costs resulted in increased investment in receivables, inventories and hedging collateral deposits in 2003.

Investing Activities

Capital spending amounted to $335.4 million in 2003. The details of capital expenditures in 2003 and 2002, and a forecast for 2004 are as follows:

Market Resources

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, the company invested $14.8 million in the Rendezvous partnership.

Natural gas transmission

During 2003, Questar Pipeline completed Tie Line 112, which increased delivery capacity to Questar Gas. Questar Pipeline also completed an interconnection with Kern River at Roberson Creek, which increased delivery capacity into that pipeline.

Natural gas distribution

During 2003, Questar Gas added 744 miles of main, feeder and service lines to provide service to 20,366 new customers.

Corporate and Other Operations

The 2004 forecast includes $25 million of yet-to-be-defined capital expenditures.

Financing Activities

Net cash flow provided from operating activities exceeded the sum of net capital expenditures and dividends by $57.5 million in 2003 and $331.0 million in 2002. The Company used surplus cash flow generated from operations to repay debt. Market Resources paid down its revolving debt by $145 million, and Questar Gas refinanced $105 million of higher-cost debt in 2003. In 2002, the Company generated more than $250 million of cash through the sale of noncore assets and used the proceeds to repay debt resulting from a 2001 acquisition of reserves and related assets.

Questar's consolidated capital structure consisted of 47% combined short- and long-term debt and 53% common shareholders' equity at December 31, 2003. A year earlier debt represented 51% and shareholders’ equity 49% of capitalization. Ratings of senior-unsecured debt as of December 31, 2003, were as follows:

Short-term borrowings amounted to $105.5 million of loans from banks at December 31, 2003, compared with $49 million a year earlier. The weighted-average interest rate on short-term debt balances at December 31 was 1.11% in 2003 and 1.62% in 2002. Questar commercial-paper borrowings are backed by short-term line-of-credit arrangements. The Company's lines-of-credit capacity as of December 31, 2003, was $210 million. Market Resources has an unrated commercial-paper program with a $100 million capacity. The subsidiary’s commercial-paper borrowings are limited to and supported by available capacity on its existing revolving-credit facility.  

Questar has an effective shelf-registration statement filed with the Securities and Exchange Commission to issue common equity or mandatory-convertible securities to fund an acquisition, although there is no current plan to issue securities under this filing.

The Company typically has negative net working capital at December 31 because of short-term borrowing. The borrowing is seasonal and generally peaks at the end of the year because of the lag in customer receivables related to cold-weather gas purchases for distribution customers.

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, Questar enters into a variety of contractual cash obligations and other commitments. 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’s operations are subject to the terms of the Wexpro Agreement.  The agreement was effective August 1, 1981, and sets forth the rights of Questar Gas’s utility operations to share in the results of Wexpro’s oil-development operations and the rate of return that Wexpro will earn for managing Questar Gas’s reserves. The agreement was approved by the PSCU and PSCW in 1981 and affirmed by the Utah Supreme Court in 1983 (See Item 8, Note 17).

Accounting for Derivatives

The Company uses derivative instruments, typically fixed-price swaps, to hedge against a decline in the average selling prices of its gas and oil production. Accounting rules for derivatives require that these instruments be marked to fair value at the balance-sheet reporting date. The difference between fair value and carrying value is reported either in net income or comprehensive income depending on the structure of the derivatives. The Company has structured virtually all energy-derivative instruments as cash-flow hedges as defined in SFAS 133 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 regional basis, gathering and processing fees, and quality.

Rate Regulation

Regulatory agencies establish rates for the storage, transportation, distribution and sale of natural gas.  The regulatory agencies also regulate, among other things, 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. Questar Gas and Questar Pipeline follow SFAS 71, "Accounting for the Effects of Certain Types of Regulation,” that requires the recording of regulatory assets and liabilities by companies subject to cost-based regulation. The Federal Energy Regulatory Commission (FERC), PSCU and PSCW have accepted the recording of regulatory assets and liabilities.

Recording of Unbilled Revenues

Questar Gas records revenues on a calendar basis even though bills are sent to customers on a cycle basis throughout the month. The company estimates revenues for the period from the date the bills are sent to customers to the end of the month. The estimates are reconciled on an annual basis in the summer when customers’ gas bills are at their lowest amount. The gas costs and other variable costs are recorded on the same basis to ensure proper matching of revenues and expenses.

Weather Normalization

Questar Gas’s tariff provides for monthly adjustments to customer charges to approximate the impact of normal temperatures on nongas revenues. Questar Gas estimates the weather-normalization adjustment for the unbilled revenue each month. The weather-normalization adjustment is evaluated each month and reconciled on an annual basis in the summer to agree with the amount billed to customers. This accounting treatment has been accepted by the PSCU and PSCW.

Group Depreciation

Both Questar Gas and Questar Pipeline use group depreciation for the majority of their fixed assets.  Under this policy, assets are depreciated in groups of similar assets rather than on an individual-asset basis. When an asset is retired, the original cost and a like amount of accumulated depreciation are removed from the books. The method typically increases depreciation expense over what would be recognized under the individual-asset method, and eliminates gains and losses when a group-depreciated asset is retired. Assets that can be separately identified, such as buildings, vehicles and computers, are depreciated on an individual-asset basis. The FERC, PSCU and PSCW have accepted the use of group depreciation.

Employee Benefit Plans

Independent consultants hired by the Company use actuarial models to calculate the yearly expenses of pension, postretirement benefits and benefit payments to recipients of a long-term disability program. The models consider mortality estimations, liability discount rates, return on investments, rate of increase of compensation, amortizing gain or loss from investments and medical-cost trend rates among the key factors. Management makes assumptions based on parameters and advice from the consultants. The Company's general policy is to make contributions to the pension fund approximately equal to the yearly expense.

Questar recorded an additional minimum pension liability of $28.7 million, a $14.7 million intangible pension asset and an after-tax comprehensive loss of $8.7 million as of December 31, 2003 related to its defined pension benefit plans. In 2001 and 2002, a decrease in the fair value of pension-plan assets, combined with a lower benefit-liability discount rate, caused the calculated accumulated-benefit obligation to exceed the fair value of the pension plan's assets. The condition can be remedied by an increase in fair value of assets, an increase in the benefit-liability discount rate and/or through additional Company contributions. The Company has no plans to materially increase the amount of its pension contributions in the near future. Improved returns on pension-plan assets in 2003 reduced the additional minimum pension liability.

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.

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

Questar’s primary market-risk exposures arise from commodity-price changes for natural gas, oil and other hydrocarbons and volatility in interest rates. A Market Resources subsidiary 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 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 intends 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 h edges 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, wa s $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 activity for 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:

OTHER INFORMATION

Western Segment of Questar Southern Trails Pipeline

Questar has invested approximately $52 million in the western segment of the Southern Trails Pipeline, which extends from the California-Arizona border to Long Beach. This investment consists of an allocation of the original price of the 16-inch-diameter line, relocation costs, and engineering costs.

Questar has been actively pursuing various alternatives for the western segment including selling the pipeline and completing the conversion of the former liquids pipeline for natural gas service. Active discussions are being held with a party interested in acquiring the pipeline and completing the conversion to gas service. Questar intends to complete the sale of the pipeline during 2004. If not, Questar will continue to pursue other alternatives, including conducting an open season to determine market support for putting the pipeline into natural gas service.

Federal Energy Regulatory Commission (FERC) – Order No. 2004 on Standards of Conduct for Transmission Providers  

In November 2003, the FERC issued final rules on "nondiscriminatory" standards when dealing with affiliated energy companies. The initial Notice of Proposed Rule Making (NOPR) would have included affiliated local-distribution companies (LDCs), such as Questar Gas, in the marketing-affiliate regulations. The final rule exempts LDCs from the regulations as long as they do not engage in off-system sales. As a policy, Questar Gas does not make off-system sales. Questar does not believe that the final order will have a significant impact on its operating costs.

FERC Rule on Quarterly Financial Reporting

The FERC issued a Rule on Quarterly Financial Reporting and Revision to the Annual Reports.  The Rule, among other issues, requires a new quarterly filing of financial statements. The FERC has not previously required quarterly statements. The added burden of preparing quarterly reports for the FERC is not expected to significantly increase operating costs.

Questar Gas Energy-Price-Risk Management

Questar Gas pursues some hedging activities to mitigate energy-price volatility for gas-distribution customers. The benefits and the costs of hedging are included in the purchased-gas-adjustment account. Questar Gas records mark-to-market adjustments for hedging contracts in the purchased-gas-adjustment account. Questar Gas had one minor gas-purchase hedge in place at December 31, 2003.

Credit Risk

Questar Pipeline requests credit support, such as letters of credit and cash deposits, from those companies that pose unfavorable credit risks. All companies posing such concerns were current on their accounts as of the date of this report. Questar Pipeline’s largest customers, other than Questar Gas, include Chevron-Texaco, Williams Energy Services, ConocoPhillips and Dominion Exploration and Production.

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.

Interest-Rate Risk Management

The Company had $950.5 million of fixed-rate long-term debt at December 31, 2003.  The fair value of fixed-rate debt is subject to change as interest rates fluctuate. The fair value of Questar's long-term debt amounted to $1.1 billion at December 31, 2003. The Company had $1.1 billion of long-term debt at December 31, 2002, of which $945.5 million was fixed-rate debt. The fair value of Questar's long-term debt amounted to $1.3 billion at December 31, 2002. If interest rates declined 10%, fair value would increase to $1.2 billion in 2003 and $1.3 billion in 2002 and interest paid on variable-rate long-term debt would decrease about $400,000. The sensitivity calculations do not represent the cost to retire the debt securities. The book value of variable-rate debt approximates fair value.

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 Common Shareholders' Equity, three years ended

December 31, 2003

Consolidated Statements 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

Shareholders and Board of Directors

Questar Corporation

We have audited the accompanying consolidated balance sheets of Questar Corporation and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, common shareholders’ 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 Corporation 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, 3 and 7 to the financial statements, Questar Corporation 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

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QUESTAR CORPORATION 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 Corporation and subsidiaries (Questar or the Company). Questar is an integrated natural gas company with two principal lines of business: nonregulated and regulated. Questar Market Resources and subsidiaries (Market Resources) conduct the nonregulated activities of gas and oil exploration, development and production, gas gathering and processing, wholesale-energy marketing, and operate a private gas-storage facility. The Company's regulated activities of natural gas distribution, interstate transmission and storage operations are conducted by Questar Regulated Services Co. and subsidiaries (Regulated Services). Questar Pipeline provides interstate natural gas transmission and storage services, and through a subsidiary, Questar Transportation Services, operates a gas-processing plant and provides gas-g athering services. Questar Gas conducts natural gas-distribution activities. Corporate and Other Operations include information-technology  related businesses, unregulated energy services and corporate activities. All significant intercompany accounts and transactions have been eliminated in consolidation.

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

Regulation:  Questar Gas is regulated by the Public Service Commission of Utah (PSCU) and the Public Service Commission of Wyoming (PSCW). The Idaho Public Utilities Commission has contracted with the PSCU for rate oversight of Questar Gas's operations in a small area of southeastern Idaho. Questar Pipeline is regulated by the Federal Energy Regulatory Commission (FERC). Market Resources, through its investment in Clear Creek Storage Company, LLC, operates a gas-storage facility that is under the jurisdiction of the FERC. These regulatory agencies establish rates for the storage, transportation and sale of natural gas. The regulatory agencies also regulate, among other things, 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.

The financial statements of rate-regulated businesses are presented in accordance with regulatory requirements. Methods of allocating costs to time periods, in order to match revenues and expenses, may differ from those of other businesses because of cost-allocation methods used in establishing rates.

Use of Estimates:  The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent liabilities reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Revenue Recognition:  Revenues are recognized in the period that services are provided or products are delivered. Questar Gas records revenues for gas delivered to residential and commercial customers but not billed at the end of the accounting period. The impact of abnormal weather on gas-distribution earnings is significantly reduced by a weather-normalization adjustment. While the transportation and storage operations of the gas-transportation business are influenced by weather conditions, the straight-fixed-variable rate design, which allows for recovery of substantially all fixed costs in the demand or reservation charge, reduces the earnings impact of weather conditions. Rate-regulated companies may collect revenues subject to possible refunds and establish reserves pending final orders from regulatory agencies.

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.

Purchased-Gas Adjustments:  Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the PSCU and the PSCW. Purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. Questar Gas hedges a portion of its natural gas supply to mitigate energy-price fluctuations for gas-distribution customers. The benefits and the costs of hedging are included in the purchased-gas-adjustment account. The regulatory commissions allow Questar Gas to record periodic mark-to-market adjustments for energy-hedging contracts in the purchased-gas-adjustment account.

Other Regulatory Assets and Liabilities:  Rate-regulated businesses may be permitted to defer recognition of certain costs, which is different from the accounting treatment required of nonrate-regulated businesses. Questar Gas recorded a regulatory asset at January 1, 2003, amounting to $6.6 million, representing a retroactive charge for the abandonment costs associated with gas wells operated on its behalf by Wexpro. The regulatory asset will be reduced over approximately 18 years following an amortization schedule or as cash is paid to plug and abandon wells. Gains and losses on the reacquisition of debt by rate-regulated companies are deferred and amortized as debt expense over either the would-be remaining life of the retired debt or the life of the replacement debt. The reacquired debt costs had a weighted-average life of approximately 15 years as of December 31, 2003. The cost of the early ret irement windows offered to employees of rate-regulated subsidiaries was capitalized and amortized over a five-year period, which will conclude in 2005. Rate-regulated operations record cumulative increases in deferred taxes as income taxes recoverable from customers, all of which are expected to be recovered in 2004. Production taxes on cost-of-service gas production are recorded when the gas is produced and recovered from customers when taxes are paid, generally within 12 months. A liability has been recorded for postretirement medical costs allowed in rates that exceed actual costs.

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

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, a subsidiary of Market Resources. 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 17).  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:

For the remaining Company properties, the provision for depreciation, depletion and amortization is based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets. The investment in natural gas-gathering and processing facilities is charged to expense using either the straight-line or unit-of-production method. For depreciation purposes, major categories of fixed assets in the gas-distribution, transmission and storage operations are grouped together and depreciated on a straight-line method. Under the group method, salvage value is not considered when determining depreciation rates. Gains and losses on asset disposals are recorded as adjustments in accumulated depreciation. Gas-production facilities are depreciated using the unit-of-production method. The Company has not capitalized future-abandonment costs on a majority of its long-lived dis tribution and transmission assets due to a lack of a legal obligation to abandon the assets or to an indeterminable abandonment date. If required, an obligation will be recognized when an abandonment date is known.

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 estimates requir e forecasts and assumptions for many years into the future for a variety of factors, including pricing and operating costs.

Goodwill and Other Intangible Assets:  Intangible assets consist primarily of goodwill acquired through business combinations. The excess of the cost over the fair value of net assets of acquired businesses is recorded as goodwill. On January 1, 2002, the Company adopted SFAS 142, "Goodwill and Other Intangible Assets." According to SFAS 142, goodwill is no longer amortized, but is tested for impairment at a minimum of once a year or when an event occurs. Annual impairment tests are conducted 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 o ther factors.

Capitalized Interest and Allowance for Funds Used During Construction:  Questar's regulated subsidiaries capitalize the cost of capital employed during the construction period of plant and equipment in accordance with guidelines from regulators. Capitalized financing costs, allowance for funds used during construction (AFUDC), consist of debt and equity portions. The debt portion of AFUDC is recorded as a reduction of interest expense, and the equity portion is recorded in other income. The Company's nonrate-regulated operations capitalize interest costs during construction of assets. Under provisions of the Wexpro agreement, AFUDC is capitalized on cost-of-service construction projects and recorded in other income. Debt expense was reduced by $126,000 in 2003, $1.3 million in 2002 and $4.1 million in 2001. AFUDC included in interest and other income amounted to $1.1 million in 2003, $3.5 million in 2002 and $5.5 million in 2001.

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 shareholders' equity.

Energy-Price Financial Instruments:  On January 1, 2001, the Company adopted the provisions of SFAS 133 as amended and recorded a cumulative effect of this accounting change that decreased other comprehensive income by $79.4 million after tax. The majority of its energy-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 individuals and 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 request s credit support and, in some 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 $3.7 million, $7.9 million and $8.6 million for the years ended December 31, 2003, 2002 and 2001, respectively. The allowance for bad-debt expenses was $6.7 million and $7.1 million at December 31, 2003, and 2002, respectively.

Income Taxes:  Questar and its subsidiaries file a consolidated federal income tax return. Deferred income taxes have been provided for temporary differences caused by differences between the book and tax-carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. Questar Gas and Questar Pipeline use the deferral method to account for investment-tax credits as required by regulatory commissions.

Earnings Per Share: Basic earnings per share (EPS) are computed by dividing net income available to common shareholders by the weighted-average number of common shares outstanding during the accounting period. Diluted EPS include the potential increase in outstanding shares that could result from exercising stock options, which is the sole difference between basic and diluted shares.

Stock-Based Compensation:  The Company accounts for employee stock-based compensation using the intrinsic-value method prescribed by Accounting Principles Board (APB) Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations. Under this method, no compensation expense is recorded for stock options granted because the exercise price of those options equals the market price of the Company's common stock on the date of grant. Compensation expense for awards of restricted shares is recognized over the vesting period, based on share value on the date of grant. A table showing income adjusted for stock-based compensation follows:

Comprehensive Income:  Comprehensive income is the sum of net income as reported in the Consolidated Statement of Income and other comprehensive income transactions reported in the Consolidated Statement of Common Shareholders' Equity. Other comprehensive income transactions result from changes in the market value of qualified energy derivatives and recognition of additional pension liability. 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 energy product is sold.

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

Business Segments:  Questar's 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 – Distribution Rate Refund – Questar Gas Processing Dispute

On August 1, 2003, the Utah Supreme Court issued an order reversing a decision made by the PSCU in August of 2000 concerning certain processing costs incurred by Questar Gas. The court ruled that the PSCU did not comply with its responsibilities and regulatory procedures when approving a stipulation in Questar Gas's general rate case filed in December of 1999. The stipulation permitted Questar Gas to collect $5 million per year in rates to recover a portion of the gas-processing costs incurred. The Committee of Consumer Services (committee), a Utah state agency, appealed the PSCU's decision because the PSCU did not explicitly address whether the costs were prudently incurred.

As a result of the court's order, Questar Gas recorded a $24.9 million liability for a potential refund to gas-distribution customers. The liability reflects revenue received for processing costs from June 1999 through December 2003. This charge reduced Questar's consolidated net income by $15.5 million, or $.18 per diluted share. Recording the liability did not have a material impact on the credit, cash or liquidity of Questar or Questar Gas. Questar Gas has requested ongoing rate coverage for gas-processing costs in its recent gas-cost pass through filing and is currently collecting these costs in rates. Until the issue is decided by the PSCU, Questar Gas will continue to record a liability for the potential refund of the ongoing gas-processing costs.

On January 21, 2004, the Committee filed a petition for extraordinary relief with the Utah Supreme Court. The committee maintained that by reopening the proceeding to review the prudence of Questar's decision making with regards to gas processing, the PSCU did not comply with the mandate of the Utah Supreme Court. The committee questioned whether the PSCU can modify post-appeal evidentiary determinations.  The company, as well as the PSCU and the Division of Public Utilities, filed memorandum opposing the committee’s filing.

Note 3 – New Accounting Standard – Accounting for Asset-Retirement Obligations

On January 1, 2003, Questar adopted SFAS 143, "Accounting for Asset Retirement Obligations," and recorded a $5.6 million after-tax charge ($.07 per diluted share) for the cumulative effect of implementing 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 noncash expenses.

With the adoption of SFAS 143, Questar 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. Questar Gas recorded a regulatory asset at January 1, 2003, amounting to $6.6 million representing a retroactive charge for the abandonment costs associated with gas wells operated on its behalf by Wexpro. The regulatory asset will be reduced over 18 years following an amortization schedule or as cash is spent to plug and abandon the gas wells. Changes in the asset-retirement obligations are shown below: