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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-Q

Commission File Number 1-8796

(801) 324-5000
(Registrant's telephone number, including area code)

Questar Corporation

Form 10-Q for the Quarterly Period Ended September 30, 2004

TABLE OF CONTENTS

Page #

PART I.

FINANCIAL INFORMATION

Item 1.

Financial Statements.

Consolidated Statements of Income for the three-and nine-months ended

     September 30, 2004 and 2003

Condensed Consolidated Balance Sheets at September 30, 2004

     and December 31, 2003

Condensed Consolidated Statements of Cash Flows for the nine-months ended

     September 30, 2004 and 2003

Notes Accompanying Consolidated Financial Statements

Item 2.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations.

Item 3.

Quantitative and Qualitative Disclosures about Market Risk.

Item 4.

Controls and Procedures.

PART II.

OTHER INFORMATION

Item 1.

Legal Proceedings.

Item 2.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity

Securities.

Item 6.

Exhibits and Reports on Form 8-K.

Signatures

Glossary of Commonly Used Terms

bbl

Barrel, which is equal to 42 United States gallons and is a common unit of measurement of crude oil.

basis

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

bcf

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

bcfe

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

Btu

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

cash flow hedge

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

degree days

A measure of the number of degrees the average daily outside temperature is above or below 65 degrees Fahrenheit.

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 drilled and found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

dth

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

exploratory well

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

futures contract

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

gross

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

hedging

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

Mbbl

One thousand barrels.

Mcf

One thousand cubic feet.

Mcfe

One thousand cubic feet of natural gas equivalents.

Mdth

One thousand decatherms.

Mdthe

One thousand decatherm equivalents.

MMbbl

One million barrels.

MMBtu

One million British Thermal Units.

MMcf

One million cubic feet.

MMcfe

One million cubic feet of natural gas equivalents.

MMdth

One million decatherms.

natural gas liquids

Liquid hydrocarbons that are extracted and separated from the natural gas

(NGL)

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

net

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

proved reserves

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

reservoir

A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

wet gas

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

working interest

An interest that gives the owner the right to drill, produce, and conduct operating activities on a property and receive a share of any production.

FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” within the meaning of Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the Securities Exchange Act of 1934 as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding the Company's future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.  In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” “forecast,” or “continue” or t he negative thereof or variations thereon or similar terminology.  Although these statements are made in good faith and are reasonable representations of Questar Corporation’s (“Questar” or the “Company”) 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:

Gas and oil reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves, the projection of future rates of production and the timing of development expenditures. The accuracy of these estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve estimates are imprecise and should be expected to change as additional information becomes available. Estimates of economically recoverable reserves and of future net cash flows prepared by different engineers or by the same engineers at different times may vary significantly. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition the estimates of future net revenues from proved reserves and the present value of those reserves are based upon certain assumptions about production levels, prices and costs, which may not be correct. The volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. Actual results may differ materially from the results estimated.  Questar Exploration and Production’s (“Questar E&P”) reserves are prepared on an annual basis by independent reservoir engineers.

The presence of wildlife and potential endangered species could limit access to public lands.  Various wildlife species occupy Questar Market Resources (“Market Resources”) leaseholds at Pinedale and in other areas. Current federal regulations restrict activities during certain times of the year on portions of Market Resources’ leaseholds due to wildlife activity and/or habitat. Some species that are known to be present, such as the sage grouse, may in the future be listed under federal law as endangered or threatened species. Such listing could have a material impact on access to Market Resources’ leaseholds in certain areas or during periods when the particular species is found to be present.

The sale of gas and oil production is a commodity-based business subject to pricing influenced by regional factors. Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. Market Resources hedges commodity prices to support credit ratings, returns on invested capital, cash-flow targets, and protect earnings from downward movements in commodity prices. However these arrangements usually limit future gains from favorable price movements.

Transmission and distribution operations are subject to regulation which can directly impact earnings.  Questar’s natural gas transmission and distribution businesses are subject to various regulated returns on rate base.  Questar monitors the allowed rates of return, its effectiveness in earning such rates and initiates rate proceedings or operating changes as needed.  In addition in the normal course of the regulatory environment, assets may be placed in service and historical test periods may need to be established before rate cases can be filed.  Once rate cases are filed, regulatory bodies have the authority to suspend implementation of the new rates while studying the cases.  Because of this process, Questar may temporarily suffer the negative financial effects of having placed assets in service without the benefit of rate relief.

Increased regulatory requirements relating to the integrity of pipelines will require Questar to spend additional money to comply with these requirements.  Questar’s gas transmission and distribution systems are subject to extensive laws and regulations related to pipeline integrity.  For example, recent federal legislation signed into law in December 2002 includes new guidelines for the U.S. Department of Transportation (“DOT”) and pipeline companies in the areas of testing, education, training and communication.  Compliance with existing and recently executed regulations requires significant expenditures. Additional laws and regulations that may be enacted in the future could significantly increase the amount of these expenditures.

Other important assumptions: changes in general economic conditions; changes in regulatory policies; regulation of the Wexpro agreement; availability and economic viability of gas and oil properties for sale or exploration; creditworthiness of counterparties; rate of inflation and interest rates; assumptions used in business combinations; weather and natural disasters; effects of environmental and other regulation; changes in customers' credit ratings; competition from other forms of energy, other pipelines and storage facilities; effects of accounting policies issued periodically by accounting standard-setting bodies; terrorist attacks or acts of war; changes in the business or financial condition of the Company; changes in credit ratings; and availability of financing for Questar and/or its subsidiaries.

NOTES ACCOMPANYING CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2004

(Unaudited)

Note 1 – Basis of Presentation of Interim Consolidated Financial Statements

The accompanying interim consolidated financial statements of Questar, with the exception of the condensed consolidated balance sheet at December 31, 2003, have not been audited by independent public accountants. The unaudited consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X.  The interim consolidated financial statements reflect all normal, recurring adjustments and accruals that are, in the opinion of management, necessary for a fair presentation of the results of operations for the interim periods presented. The preparation of consolidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect the amounts o f assets and liabilities and disclosure of contingent assets and liabilities. Actual results could differ from estimates. All significant intercompany accounts and transactions were eliminated in consolidation.

The results of operations for the three- and nine-month periods ended September 30, 2004, are not necessarily indicative of the results that may be expected for the year ending December 31, 2004, due to the volatility of gas and oil sales prices, the seasonal nature of the gas-distribution business and other risk factors listed in the Forward-Looking Statements section of this report.  Interim consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. For further information please refer to the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.

Certain reclassifications were made to the 2003 financial statements to conform with the 2004 presentation.

Note 2 – Asset-Retirement Obligations (“ARO”)

On January 1, 2003, Questar adopted SFAS 143 “Accounting for Asset Retirement Obligations.” 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 fair value of abandonment costs are estimated and depreciated over the life of the related assets. ARO are adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate.

Changes in asset-retirement obligations were as follows.

During the second quarter of 2004, Wexpro finalized a guideline letter with the Utah Division of Public Utilities and the staff of the Wyoming Public Service Commission (“PSCW”) agreeing to the accounting treatment of reclamation activity associated with ARO for properties administered under the Wexpro agreement. Pursuant to the stipulation, Wexpro collects and deposits in trust certain funds related to estimated ARO costs.  The funds are used to satisfy retirement obligations as the properties are abandoned.

Note 3 – Questar Gas Processing Dispute

On August 1, 2003, the Utah Supreme Court issued an order reversing an August 2000 decision made by the Public Service Commission of Utah (“PSCU”) concerning certain natural gas processing costs incurred by Questar Gas Company (“Questar Gas”).  The court ruled that the PSCU did not comply with its statutory responsibilities and regulatory procedures when approving a stipulation in Questar Gas’s 1999 general rate case. The stipulation permitted Questar Gas to collect $5.0 million per year through May 2004 to recover a portion of the processing costs.  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 prudent.

As a result of the court’s order, Questar Gas recorded a liability for a potential refund to gas-distribution customers. The current liability of $29.0 million, including $4.1 million recorded in the first nine months of 2004, reflects revenue received for processing costs and interest from September 1999 through September 2004.

On August 30, 2004, after hearings held in May 2004, the PSCU ruled that Questar Gas failed to prove prudence in contracting for gas processing in response to the changes in the heat content of its gas supply.  The PSCU reversed the stipulation, denied the request for rate recovery and ordered the refund of costs previously collected in rates.  Since Questar Gas had accrued a liability for the potential refund, the order did not have a material impact on earnings for the third quarter of 2004.  In addition, the order did not have a material impact on the creditworthiness, cash flow or liquidity of Questar or Questar Gas.  Questar Gas reduced its rates on September 1, 2004, to eliminate the collection of gas-processing costs and on October 1 began refunding previously collected costs, plus interest over a 12 month period as ordered by the PSCU.

On September 30, 2004, Questar Gas filed a petition with the PSCU for reconsideration or clarification of the August 30, 2004 order.  On October 20, the PSCU declined to reconsider its order, but clarified that its order did not preclude recovery of ongoing and certain past processing costs. Ongoing processing costs are approximately $7 million per year.

Questar Gas has requested ongoing rate coverage for gas processing costs in its pass through filings, but are not currently collecting these costs in rates.  The PSCU has scheduled several technical conferences to determine how to resolve issues of managing heat content of gas supply.  

Note 4 – Earnings Per Share (“EPS”)

Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the accounting period.  Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options plus the estimated number of nonvested restricted shares.

In the first nine months of 2004, Questar issued 1,044,000 shares under the terms of the Long-Term Stock Incentive Plan, the Dividend Reinvestment and Stock Purchase Plan and the Employee Investment Plan.

Note 5 – Stock-Based Compensation

The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion 25, “Accounting for Stock Issued to Employees” and related interpretations. No compensation expense is recorded because the exercise price of options is equal to the market price on the date of grant. The table below shows pro forma income had options been expensed according to SFAS 123 “Accounting for Stock-Based Compensation” based on fair-value calculated using the Black-Scholes model.

Net income, as reported in the table above, reflects expenses related to restricted stock awards.  Restricted shares are valued at the market price on the grant date and amortized over the vesting period.  Expense for the nine months ended September 30, 2004 and 2003, amounted to $1.7 million and $900,000, respectively.

Note 6 – Operations by Line of Business

Questar has four primary reportable segments:  Market Resources, Questar Pipeline, Questar Gas and Corporate and other operations.  Lines of business information are presented according to senior management’s basis for evaluating performance including differences in the nature of products, services and regulation.

Note 7 – Employee Benefits

Questar has defined-benefit pension and postretirement medical and life insurance plans covering the majority of its employees.  Questar complies with minimum-required and maximum-allowed annual contribution levels for its qualified retirement plan as determined by the Employee Retirement Income Security Act and Internal Revenue Code. Subject to these limitations Questar's objective is to fund the qualified retirement plan in amounts approximately equal to the yearly expense. Presently the pension expense estimate for 2004 is $15.6 million. Components of pension expense included in the determination of interim net income are listed below.

Questar recognized the impact of the Medicare Prescription Drug, Improvement and Modernization Act beginning in the third quarter of 2004 resulting in a slight decrease in expense that is being amortized over future periods as an actuarial gain.

Pension Expense

Expense of Postretirement Benefits Other than Pensions

The Company currently estimates a $5.3 million expense for postretirement benefits in 2004 before $800,000 for accretion of a regulatory liability.  Expense components are listed below.

Note 8 – Financing

On June 21, 2004, Questar Gas called $17 million in medium-term notes that carried an interest rate of 8.12%.  A call premium of $690,000 will be amortized over the remaining life of the original notes in accordance with regulatory treatment.

On March 19, 2004, Market Resources completed a $200 million credit facility with a consortium of banks that replaced an existing facility that expired in April 2004. The facility allows for floating-rate interest and revolving loans of various maturities until March 2009. Key financial covenants place limits on minimum levels of cash flow compared to interest expense and maximum amounts of debt as a percentage of total capital. The interest rate credit spread on borrowings varies with changes in Market Resources’ credit rating, but a reduction in or loss of credit ratings does not trigger an event of default under the facility.

Note 9 – Investment in Unconsolidated Affiliates

Questar uses the equity method to account for investments in unconsolidated affiliates where the Company does not have control. These entities are engaged in gathering and compressing natural gas, and have no debt obligations with third-party lenders. The principal affiliates and Questar's ownership percentage as of September 30, 2004, were: Rendezvous Gas Services, LLC, a limited liability corporation, (50%) and Canyon Creek Compression Co., a general partnership (15%).

Operating results are listed below.

Note 10 – Comprehensive Income

Comprehensive income is the sum of net income as reported in the Consolidated Statements of Income and other comprehensive income or loss reported in Common Shareholders' Equity. Other comprehensive income or loss includes changes in the market value of gas or oil-price derivatives. These results are not reported in current income or loss. Income or loss is realized when the physical gas or oil underlying the derivative instrument is sold. A summary of comprehensive income is shown below.

The components of accumulated other comprehensive loss are as follows, net of income taxes:

Note 11 – Recent Accounting Developments

On October 13, 2004, the Financial Accounting Standards Board (“FASB”) concluded that all companies would be required to measure costs for stock-based awards using estimated fair value on the date of grant.  SFAS 123R “Share-Based Payments” applies to all awards granted, modified or settled for periods beginning July 1, 2005.  Questar issues stock options and restricted shares to employees and non-employee directors.  Currently Questar accounts for stock options under the intrinsic-value method where no expense is recorded.  SFAS 123R will change this treatment and require recognition of costs in the consolidated statement of income.  Questar has measured the impact and disclosed the pro forma effect in Note 5 of this report.  FASB expects to issue a final version of SFAS 123R by December, 2004.

As of the end of 2003, the FASB was considering whether oil and gas drilling and mineral rights were subject to the classification and disclosure provisions of SFAS 142, “Goodwill and Other Intangible Assets.”  In September 2004 the FASB issued FASB Staff Position (“FSP”) FAS 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets to Oil and Gas Producing Entities.”  This FSP confirms that SFAS 142 did not change the balance sheet classification or disclosure requirements for drilling and mineral rights of companies in the exploration and production business.  Market Resources classifies the costs associated with drilling and mineral rights, including both proved and unproved lease-acquisition costs, as property, plant and equipment.

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

September 30, 2004

(Unaudited)

Results of Operations

Questar Corporation (“Questar” or “the Company”) is a natural gas-focused energy company that conducts operations through three primary entities. Questar Market Resources (“Market Resources”), through various subsidiaries, engages in gas and oil acquisition, exploration, development and production; cost-of-service gas development; gas-gathering and processing services; and wholesale gas and hydrocarbon-liquids marketing, risk management, and gas storage. Questar Pipeline Company (“Questar Pipeline”) conducts interstate gas-transmission and storage activities. Questar Gas Company (“Questar Gas”) provides retail gas distribution services.

SUMMARY

Questar reported net income for the first nine months of 2004 of $155.6 million or $1.82 per diluted share compared to $113.6 million or $1.35 per share for the first nine months of 2003. The 2003 period’s net income was reduced by $5.6 million or $0.07 per share related to the implementation of SFAS 143. Following is a comparison of net income by line of business.

Market Resources net income increased 38% in the first nine months of 2004 compared to the same period of 2003.  Primary factors were a 12% increase in nonregulated production, higher realized natural gas, oil and natural gas liquids prices, increased gas-gathering throughput and processing margins, and additions to Wexpro’s investment base. Implementation of SFAS 143 reduced earnings in 2003 by $5.1 million.

Questar Pipeline net income increased 1% in the first nine months of 2004 compared with the first nine months of 2003. A 5% increase in revenues was offset by a 9% increase in total operating expenses. Implementation of SFAS 143 reduced 2003 net income by $133,000.

Questar Gas net income increased in the first nine months of 2004 compared with the first nine months of 2003.  The 2003 results include a $14.5 million after-tax charge for a refund of disputed-gas processing costs of which $11.9 million related to periods prior to 2003. Net income decreased about $400,000 in the first nine months of 2004 compared with the first nine months of 2003 excluding the impact of the refund primarily due to higher expenses and lower usage per customer more than offsetting revenues from new customers. Implementation of SFAS 143 reduced 2003 earnings by $334,000.

Net income from Corporate and other operations decreased $1.4 million in the first nine months of 2004 compared to the same period of 2003 because of reduced services.

Market Resources

Market Resources conducts its operations through several subsidiaries. Questar Exploration and Production Company (“Questar E&P”) acquires, explores for, develops and produces gas and oil. Wexpro Company (“Wexpro”) manages, develops and produces cost-of-service reserves for affiliated company, Questar Gas. Questar Gas Management Company (“Gas Management”) provides gas-gathering and processing services for affiliates and third parties. Questar Energy Trading Company (“Energy Trading”) markets equity and third-party gas and oil, provides risk-management services, and through its wholly-owned subsidiary Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir. Following is a summary of Market Resources’ financial results and operating information.

Market Resources Consolidated Results

Market Resources net income for the third quarter of 2004 totaled $37.2 million compared with $27.4 million for the year earlier period, a 36% increase.  Net income for the first nine months of 2004 was $115.6 million, a 38% increase over the $84.1 million earned in the same period in 2003, as revenue growth continued to outpace increases in expenses.  Operating income increased $15.9 million, or 33%, in the quarter-to-quarter comparison and $43.3 million, or 28%, in the nine month comparison, due primarily to increased production and higher prices at Questar E&P and increased throughput and improved margins at Gas Management.  

Total revenues increased $75.3 million, or 36%, in the third quarter of 2004, and $196.6 million, or 31%, in the first nine months of 2004. Revenue growth was driven by increased nonregulated production (nonregulated production excludes oil and cost-of-service gas produced by Wexpro), higher realized natural gas, oil and NGL prices at Questar E&P, and increased throughput and higher fees at Gas Management.  Expenses increased in the 2004 periods due to increased abandonment expense, production taxes, lease operating expense, and depreciation, depletion and amortization.

Questar E&P Results

For the third quarter of 2004, Questar E&P earned $24.8 million compared with $17.3 million for the same period in 2003.  Net income for the first nine months of 2004 was $75.4 million, a 49% increase over the $50.8 million earned in 2003.  Higher profits were driven by increased nonregulated production and higher realized natural gas, oil and NGL prices.

Questar E&P’s nonregulated production for the first nine months of 2004 was 75.8 bcfe compared to 67.9 bcfe for the 2003 period, a 12% increase.    Production growth was driven by accelerated development drilling on the Pinedale Anticline in western Wyoming and a 17% year-over-year increase from Midcontinent properties. Natural gas remains the primary focus of Questar E&P’s exploration and production strategy.  On an energy-equivalent ratio, natural gas comprised approximately 86% of nonregulated production for the third quarter and first nine months of 2004.  The three-and nine-month comparisons of energy-equivalent production by region are shown in the following table.

At September 30, 2004, Market Resources operated 88 producing wells on the Pinedale Anticline compared to 58 at the end of the year earlier quarter.  Current quarter nonregulated production from Pinedale was 5.1 bcfe compared to 4.9 bcfe in the second quarter and 6.1 bcfe in the first quarter of 2004.  Production at Pinedale typically declines during the second and third quarters due to the suspension of drilling and completion activities caused by access restrictions from mid-November to early May.  (See the discussion of Pinedale Anticline Drilling Activity later in this Item.) Production volumes from the Uinta Basin in eastern Utah decreased 12% in the current quarter compared to the year earlier period and 17% in the first nine months of 2004 versus the year earlier period. Production decline in the Uinta Basin has flattened significantly from a year ago.  Curren t quarter production from Uinta Basin was 6.4 bcfe compared to 6.1 bcfe in the second quarter and 6.3 bcfe in the first quarter of 2004.  Production from Rockies legacy properties in the first nine months of 2004 was 13.5 bcfe compared to 12.4 bcfe in 2003, a 9% increase. Legacy properties include all of Questar E&P’s Rocky Mountain producing properties exclusive of Pinedale and the Uinta Basin.  Continued good performance from Questar E&P’s Hartshorne coalbed-methane development project in the Arkoma Basin of eastern Oklahoma and ongoing infill-development drilling on the Elm Grove properties in northwest Louisiana drove Midcontinent results.  Current quarter Midcontinent production was up 1.5 bcfe, or 18%, versus the third quarter of 2003.

Questar E&P benefited from higher realized prices for natural gas, oil and NGL in the third quarter and first nine months of 2004.  For the current quarter the weighted average realized natural gas price for Questar E&P (including the effects of hedging) was $4.07 per Mcf compared to $3.56 per Mcf for the same period in 2003, a 14% increase.  For the 2004 quarter, realized oil and NGL prices averaged $31.83 per bbl, compared with $22.69 per bbl in the third quarter of 2003, a 40% increase.  A comparison of average realized prices by region, including hedges, is shown in the following table.

Realized natural gas prices in Questar E&P’s core Rockies areas increased significantly in the third quarter and first nine months of 2004 compared to the 2003 periods.  Approximately 63% of Questar E&P’s 2004 natural gas production came from properties located in the Rockies.  Rockies basis, the regional difference between Rockies prices and the reference Henry Hub price, averaged approximately $0.68 per MMBtu for the third quarter of 2004, compared to $0.60 per MMBtu for the same period in 2003.  For the first nine months of 2004 the Rockies basis averaged approximately $0.79, compared to $1.56 in the first nine months of 2003.  The May 2003 completion of a major interstate pipeline expansion that delivers Rockies gas to California markets alleviated the transportation bottleneck that adversely affected prices in the 2003 periods.

Approximately 78% of Market Resources’ nonregulated gas production in the first nine months of 2004 was hedged or pre-sold at an average price of $4.03 per Mcf net to the well (which reflects adjustments for regional basis, gathering and processing costs, and gas quality).  Hedging reduced gas revenues $51.9 million in the first nine months of 2004.  Market Resources also hedged or pre-sold approximately 62% of its oil production for the first nine months of 2004 at an average net to the well price of $30.98 per bbl. Hedging reduced oil revenues $9.6 million during the first nine months of 2004.  Market Resources may hedge up to 100 percent of its forecasted nonregulated production from proved developed reserves to lock in acceptable returns on invested capital and to protect cash flows and earnings from a decline in commodity prices.  Market Resources has continued to take advantage of higher natural gas and oil prices to add to its hedge positions in 2005, 2006 and 2007. Natural gas and oil hedges as of September 30, 2004, are summarized in Item 3 of this report.

Questar E&P’s cost structure is summarized in the following table.

Lifting costs per Mcfe were higher in the 2004 periods primarily due to increased production taxes related to higher natural gas, oil and NGL sales prices. Most production taxes are based on a fixed percentage of commodity sales prices. Depreciation, depletion and amortization expense increased in the 2004 periods primarily due to higher reserve replacement costs.  Increased competition for rigs and other services in core operating areas, along with sharply higher steel prices, has increased drilling and completion costs.  General and administrative expenses per Mcfe increased $0.02, or 7%, in the first nine months of 2004 when compared to the same period in 2003.  The increase was primarily due to higher legal, insurance, and employee benefit costs and higher allocated corporate overhead (primarily employee benefits and compliance costs).  For the third quarter and first n ine months of 2004 allocated interest decreased to $0.22 and $0.21 per Mcfe compared to $0.23 and $0.24 per Mcfe for the same periods in 2003 due mostly to increased production.

Pinedale Anticline Drilling Activity

Market Resources was permitted to drill three wells from a single pad over the winter of 2003/2004 pursuant to an exception to the November 15 through May 1 drilling restrictions.  Sage grouse stipulations imposed by the Bureau of Land Management (“BLM”) further delayed startup of drilling activities at some locations on Market Resources’ Pinedale acreage during both May and September, including the 19,500 foot deep Stewart Point 15-29 well which could not be spud until mid July.  The drilling pace on the Stewart Point well has been hampered by chronic mechanical problems on the contracted drilling rig and inexperienced rig crews.  Market Resources will likely suspend operations on the well in mid-November and resume in the spring with a new rig and drilling contractor.

At September 30, 2004, Market Resources had 14 rigs actively drilling on its Pinedale acreage.  In spite of delays Market Resources still expects to drill and complete approximately 30 Lance/Mesaverde Formation development wells in 2004.

Pinedale Anticline Year-Round Drilling Proposal

On April 15, 2004, Market Resources submitted a proposal to the BLM seeking a long-term exception to the winter drilling restrictions on its Pinedale acreage from November 15 through May 1. If approved, Market Resources will be allowed to drill from three active pads with two drilling rigs per pad, starting in the winter of 2004/2005. The BLM initiated an Environmental Assessment and solicited public comments on Market Resources’ proposal.  The BLM’s decision on Market Resources’ proposal is expected in time for the 2004/2005 winter drilling season.  Certain groups have sued the BLM over granting Market Resources prior winter-long exceptions to winter stipulations at Pinedale and the case is still pending.

Market Resources believes that year-round drilling from pads is the most efficient and environmentally responsible approach for developing its Pinedale acreage. Market Resources’ proposal would shorten the anticipated development drilling period from 18 years to about 9 years. Under the proposal Market Resources would drill multiple directional wells from single surface pads. If approved Market Resources estimates that only nine additional surface disturbances will be required to fully develop its current Pinedale acreage held at the end of 2003 on 20-acre spacing. With Market Resources’ proposal, surface disturbance will be reduced initially from almost 1,500 acres currently allowed to less than 540 acres.  Surface disturbance would be further reduced to about 260 acres with post-drilling reclamation.

In addition to reduced surface disturbance and a shortened development drilling period, other benefits of Market Resources’ year-round proposal include a substantial reduction in emissions, noise, dust and traffic compared to the current situation in which activities are compressed into the summer months. Year-round drilling also creates year-round jobs and thus a more stable, better trained, more productive and safer workforce in the drilling and completion service industries.  If the proposal is approved, Market Resources has committed to build pipelines to transport condensate and water production off the portion of the Pinedale Anticline where Market Resources’ acreage is located. The pipelines will eliminate the need for storage tanks at each location and up to 25,500 tanker-truck trips per year at peak production.  

Pinedale Anticline 20-Acre Spacing Approved

During the third quarter, the Wyoming Oil and Gas Conservation Commission issued a formal order approving 20-acre density drilling of Lance Pool (Lance and Mesaverde Formation) wells on Market Resources Pinedale Anticline acreage held at the end of 2003 (approximately 14,800 acres).   With 20-acre spacing Market Resources has up to 430 total well locations on its Pinedale leasehold, with approximately 324 remaining to be drilled after 2004. Market Resources estimates that each 20-acre-spaced well drilled and completed in the Lance and Mesaverde Formations will recover between 3.8 and 8.8 bcfe of gross incremental reserves.  As a result Questar E&P expects to book an incremental 250-300 bcfe of proved reserves at Pinedale by year end 2004.  There are approximately 125 additional locations that cannot be booked as proved at this time because they do not directly offset cu rrently producing wells.  Pursuant to Securities and Exchange Commission reserve-booking guidelines, only locations that directly offset currently producing wells can be booked as proved.

New Pinedale Leases

Questar E&P and Wexpro have a combined 62% average Lance/Mesaverde working interest in 14,800 acres at Pinedale. During the third quarter, Questar E&P acquired new federal leases on 2,018 acres adjacent to the southwest side of the current 14,800 acre leasehold.  This newly acquired Pinedale acreage may add up to 32 low-risk 20-acre drilling locations.  Questar E&P has a 100% working interest in these new leases.  Several groups have appealed the issuance of these leases.

Wexpro

For the third quarter of 2004 Wexpro earned $8.7 million, compared with $7.8 million for the same period in 2003.  Net income for the first nine months of 2004 was $26.5 million, an 11% increase over the $23.9 million earned in 2003.  Wexpro manages, develops and produces gas reserves on behalf of Questar Gas. Wexpro activities are governed by a long-standing agreement (“Wexpro Agreement”) with the States of Utah and Wyoming.  Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an after-tax return of approximately 19% on its net investment in commercial wells and related facilities – known as the investment base – adjusted for working capital, deferred taxes, and depreciation.  Wexpro’s net investment base increased to $165.0 million at September 30, 2004, up $3.8 million over the year earlier period.  Wexpro’s net inc ome also benefited from higher oil and NGL prices in the 2004 periods.

Gas Gathering and Processing; Gas and Oil Marketing

Net income from gas gathering, processing and marketing operations increased 66% to $3.7 million in the third quarter of 2004 from $2.2 million in the 2003 period.  Net income for the first nine months of 2004 was $13.7 million versus $9.4 million for the same period in 2003, an increase of 45%.  Gathering volumes increased 15% to 167.9 MMdth for the first nine months of 2004 due primarily to expanding Pinedale production and new projects serving third parties in the Uinta Basin.  Gas Management gas-processing margins (revenue from the sale of natural gas liquids less natural gas purchases and operating expenses) improved by $0.05 per gallon due to higher NGL sales prices.  Pre-tax earnings from Gas Management’s 50% interest in Rendezvous increased to $3.5 million for the nine months ended September 30, 2004, from $3.4 million for the comparable 2003 period.  Rend ezvous provides gas gathering services for the Pinedale and Jonah producing areas.  Gas Management continues to invest in additional gas gathering and processing and liquids-handling facilities to serve growing equity and third-party production in its core areas.  These core areas are the Pinedale and Jonah fields in western Wyoming and the Uinta Basin in eastern Utah.

Gross margins for gas and oil marketing (gross revenues less the costs to purchase gas and oil, commitments to gas transportation contracts on interstate pipelines, and gas storage costs), increased to $13.2 million for the first nine months of 2004 versus $10.7 million for the year earlier period, a 23% increase.  The increase was due primarily to a 4% higher unit margin and a 19% increase in volumes over the same period last year.  

Energy Trading is the sole owner of Clear Creek Storage, LLC, which owns and operates the Clear Creek natural gas storage facility in southwestern Wyoming.  Clear Creek has working gas storage capacity of approximately 3.0 bcf and is connected to four interstate pipelines – Kern River, Northwest, Overthrust and Questar Pipeline.

Questar Pipeline

Questar Pipeline provides Federal Energy Regulatory Commission (“FERC”) regulated interstate natural gas transmission and storage, and non-jurisdictional processing and gathering services. Following is a summary of financial results and operating information.

Questar Pipeline’s net income was $8.0 million in the third quarter of 2004 and $23.4 million in the first nine months of 2004 compared with $7.9 million in the third quarter of 2003 and $23.1 million in the first nine months of 2003.  The 2004 results reflect new firm-transmission contracts and higher liquid revenues offset by higher operating costs.

Questar Pipeline’s revenues grew 7% in the third quarter of 2004 and 5% in the first nine months ended September 30, 2004, compared with the year-earlier periods. Gas transportation volumes declined in the 2004 periods due to reduced demand for electric generation and reduced interruptible transportation.  These reductions were partially offset by increased volumes transported for Questar Gas due to colder weather.  Following is a summary of major changes in Questar Pipeline’s revenues for the three months and nine months ended September 30, 2004, compared with the same periods of 2003.

Questar Pipeline has 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 at Roberson Creek and for increased deliveries to Questar Gas.

Questar Pipeline’s existing transportation system is nearly fully subscribed. As of September 30, 2004, Questar Pipeline had firm-transportation contracts of 1,644 Mdth per day compared with 1,655 Mdth per day as of December 31, 2003, and 1,614 Mdth per day as of September 30, 2003. The amounts include 80 Mdth per day capacity on the eastern segment of Southern Trails.  Questar Pipeline’s firm-transportation contracts had a weighted average remaining life of 9.1 years as of September 30, 2004.  

Questar Gas is Questar Pipeline’s largest transportation customer with contracts for 951 Mdth per day, including 50 Mdth 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. In addition to Clay Basin Questar Pipeline also owns and operates three smaller aquifer gas storage facilities.  Questar Pipeline’s firm storage contracts had a weighted average remaining life of 7.4 years as of September 30, 2004.

Questar Gas has contracted for 62% of firm-storage capacity at Clay Basin for terms extending from four to 15 years and 100% of the firm-storage capacity at the aquifer facilities for terms extending for 15 years.

Questar Pipeline charges FERC-approved transportation and storage rates that are based on straight-fixed-variable rate design. Under this rate design all fixed costs of providing service including depreciation and return on investment are recovered through the demand charge. About 95% of Questar Pipeline costs are fixed and recovered through these demand charges.  Questar Pipeline’s earnings are driven primarily by demand revenues from firm shippers.  Operating costs that vary based on throughput are recovered through volumetric charges. Since demand charges are based on contract levels and volumetric charges are about 5%, period-to-period changes in firm-transportation volumes do not have a significant impact on earnings.

Operating and maintenance expenses increased 17% in the third quarter of 2004 and 9% in the first nine months of 2004 over the corresponding 2003 periods.  The increases for all periods presented were primarily for processing plant fuel gas, employee benefits, insurance and maintenance.  Operating and maintenance expenses per dth transported were $0.150 in the first nine months of 2004 compared with $0.128 in the first nine months of 2003.

Depreciation and property-tax expenses increased in the 2004 periods reflecting increased pipeline investment.

Questar Pipeline is investigating a potential discrepancy of up to 11 bcf between the book volume of cushion gas at Clay Basin and indicated volumes of cushion gas in the storage reservoir based on pressure survey data obtained in recent field tests. The current book volume of the cushion gas is 61.5 bcf with a book value of $99.7 million. The cause and significance of this discrepancy is unknown at this point. Possible explanations include errors in measurement, leaks in the storage reservoir or in wells that permit migration of gas outside of the reservoir, or physical changes in the character of the storage reservoir. Initial reviews of accounting and measurement data confirm the book volume.  Analysis to date has not revealed any leaks or gas migration. Additional tests and analysis, and reservoir modeling are underway to identify the cause and may continue for several years.  Pr essure survey tests were conducted during October 2004 to evaluate the reservoir when it was nearly full.  The results of these tests are being evaluated. Questar Pipeline at this time does not know if the volume of gas actually in the reservoir is less than book volume. Questar Pipeline will not know the financial impact, if any, until the cause of the disparity is determined.  Investigations indicate that storage service obligations will continue to be met.

Questar Pipeline confirmed that the disparity first occurred in the mid-1990s, when the working capacity of the reservoir was expanded.  The disparity may be due to gas being pushed into portions of the reservoir that are ineffective.  The gas may still be in the reservoir but not detectible with short-duration pressure surveys.

If Questar Pipeline determines that the discrepancy is due to changes in the physical conditions in the storage reservoir and not of loss of cushion gas, the financial impact may include some additional investment in cushion gas to meet service obligations.  If the discrepancy is due to lost-and-unaccounted-for-gas in the measurement process, Questar Pipeline would expense the cost of replacement gas and could file with the FERC to recover costs from customers.

During first quarter 2004 Questar Pipeline obtained long-term contracts to support a $54 million expansion of its central Utah transmission system. The expansion will add 102 Mdth per day of capacity from the Piceance and Uinta basins to the Kern River pipeline, a power-generation facility, and Questar Gas’s distribution system.  Questar Pipeline will start construction in the summer of 2005 for a late-2005 in-service date.  On October 12, 2004, Questar Pipeline filed an application with the FERC to construct the expansion.  Annual revenues from this expansion will be about $9.7 million and net income of $800,000 in 2005.

Questar Pipeline also obtained a long-term contract supporting a $14 million extension from the west end of its Mainline 104 near Goshen, Utah to a new power plant being built near Mona, Utah. This 190 Mdth line is under construction and is scheduled to be in-service by the end of 2004.  This extension is expected to generate about $2.5 million of revenues and $800,000 of net income in 2005.

Questar Transportation Services, a subsidiary of Questar Pipeline, owns non-jurisdictional gathering lines and a processing plant near Price, Utah.  The plant 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 western segment of the Southern Trails Pipeline, which runs from the California-Arizona border to Long Beach, California, is currently not in service.  Questar Pipeline’s investment in this asset is approximately $51 million.  Questar Pipeline is actively seeking customers, including the Los Angeles Department of Water and Power (“LADWP”).  LADWP budgeted funds to acquire a gas pipeline and issued a request for proposal on October 21, 2004, for gas transportation service to a power-generation facility. Questar Pipeline believes the western segment is a unique solution for LADWP’s gas transportation needs and will file a response to the request for proposal by the end of November.  

FERC Order No. 2004, which defines standards of conduct for transmission providers, became effective on September 22, 2004.  These standards of conduct are designed to ensure that employees engaged in transmission system operations function independently from employees of marketing and energy affiliates.  In addition a transmission provider must treat all transmission customers on a non-discriminatory basis and must not operate its transmission system to preferentially benefit its marketing or energy affiliates.  Questar Pipeline has determined that Market Resources, Questar E&P, Energy Trading and Wexpro are marketing or energy affiliates.  Base on clarification from the FERC, Questar Pipeline believes that Questar Gas is not an energy affiliate.  Questar Pipeline and other Questar companies have adopted new procedures to comply with this order.

Questar Pipeline is required to comply with the Pipeline Safety Improvement Act of 2002 (the “Safety Act”).  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 locations.  Questar Pipeline estimates that its annual cost to comply with the act will be approximately $1 million, not including costs of pipeline replacement, if necessary.

Questar Pipeline made an annual tracking filing with the FERC on November 28, 2003, to reflect an increase in its fuel-gas reimbursement percentage from 1.4% to 1.8%.  Several shippers intervened and protested the filing.  On December 31, 2003, the FERC accepted Questar Pipeline’s filing, effective January 1, 2004.  Subsequently several parties requested a rehearing of the December order.  The FERC held a technical rehearing conference on July 29, 2004, and allowed all parties to file comments.  The FERC will issue a decision on the rehearing requests, but there is no specific time frame for the decision.

Questar Gas

Questar Gas distributes natural gas in Utah, southwestern Wyoming and southeastern Idaho. Following is a summary of financial results and operating information.

Questar Gas lost $9.8 million in the third quarter of 2004 and reported income of $12.5 million in the first nine months of 2004 compared with a loss of $8.3 million in the third quarter of 2003 and income of $1.0 million in the first nine months of 2003.  The 2003 second quarter results included an expense of $22.0 million ($13.6 million after-tax) for a potential refund to customers for gas-processing costs.  Of this amount, $11.9 million related to periods prior to 2003.  

Questar Gas’s margin was flat in the third quarter of 2004 and increased 1% in the first nine months of 2004 compared with the 2003 periods. Following is a summary of major changes in Questar Gas’s margin for the third quarter of 2004 and first nine months of 2004.

At September 30, 2004, Questar Gas was serving 778,992 customers. Customer growth remained above national averages at 3.1% over the prior year. Housing construction in Utah remained strong, driven by low mortgage-interest rates. Usage per customer, adjusted for normal temperatures, was up 4% in the third quarter of 2004 and declined 3% in the first nine months of 2004 compared with the 2003 periods.  Usage per customer has been decreasing due to more efficient appliances and homes and customer response to higher prices.

Weather, as measured in degree days, was 26% colder than normal in the third quarter of 2004 and 7% colder than normal in the first nine months of 2004 compared with 9% warmer than normal in the third quarter and first nine months of 2003. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations.

Industrial deliveries declined 18% in the third quarter of 2004 and 9% in the first nine months of 2004 compared with the 2003 periods primarily driven by lower power-generation requirements.

Cost of natural gas sold increased 24% in the third quarter of 2004 and 39% in the first nine months of 2004 compared with the 2003 periods.  These changes were due to increased volumes and increased natural gas purchase costs.  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.  As of September 30, 2004, Questar Gas had a $36.1 million balance in the purchased-gas adjustment account representing gas costs incurred but not yet recovered from customers. Effective October 1, 2004, the PSCU and PSCW authorized Questar Gas to increase customer rates by about 10% to reflect higher projected gas costs and to recover the balance in the purchase-gas adjustment account.

Operating and maintenance expenses increased 6% in the third quarter of 2004 and 3% in the first nine months of 2004 compared with the 2003 periods.  Higher contracted services and bad-debt costs were partially offset by lower information technology and labor costs.  

Depreciation expense increased 15% in the third quarter of 2004 and 5% in the first nine months of 2004 compared with the 2003 periods. Plant additions, including a customer information system that was placed in service in July 2004 have increased depreciation expense.

On August 1, 2003, the Utah Supreme Court issued an order reversing an August 2000 decision made by the PSCU concerning certain natural gas processing costs incurred by Questar Gas.  The court ruled that the PSCU did not comply with its statutory responsibilities and regulatory procedures when approving a stipulation in Questar Gas’s 1999 general rate case. The stipulation permitted Questar Gas to collect $5.0 million per year through May 2004 to recover a portion of the processing costs.  The Committee, a Utah state agency, appealed the PSCU’s decision because the PSCU did not explicitly address whether the costs were prudent.

As a result of the court’s order, Questar Gas recorded a liability for a potential refund to gas-distribution customers. The current liability of $29.0 million, including $4.1 million recorded in the first nine months of 2004, reflects revenue received for processing costs and interest from September 1999 through September 2004.

On August 30, 2004, after hearings held in May 2004, the PSCU ruled that Questar Gas failed to prove prudence in contracting for gas processing in response to the changes in the heat content of its gas supply.  The PSCU rejected the stipulation, denied the request for rate recovery and ordered the refund of costs previously collected in rates.  Since Questar Gas had accrued a liability for the refund, the order did not have a material impact on earnings for the third quarter of 2004.  In addition, the order did not have a material impact on the creditworthiness, cash flow or liquidity of Questar or Questar Gas.  Questar Gas reduced its rates on September 1, 2004, to eliminate the collection of gas-processing costs and on October 1 began refunding previously collected costs, plus interest over a 12 month period as ordered by the PSCU.

On September 30, 2004, Questar Gas filed a petition with the PSCU for reconsideration or clarification of the August 30, 2004 order.  On October 20, the PSCU declined to reconsider its order, but clarified that its order did not preclude recovery of ongoing and certain past processing costs. Ongoing processing costs are approximately $7 million per year.

Questar Gas has requested ongoing rate coverage for gas processing costs in its pass through filings, but are not currently collecting these costs in rates.  The PSCU has scheduled several technical conferences to determine how to resolve issues of managing heat content of gas supply.

In July 2004, Questar Gas implemented a new customer information system.  The new system provides critical customer service functions including billing, collections, cash receipts, customer sign-up, service requests and dispatch.  The implementation took approximately 18 months and cost approximately $20 million.

Questar Gas is also required to comply with the requirements of the Safety Act.  Questar Gas estimates that its annual cost to comply with the act will be approximately $5 million, not including costs of pipeline replacement if necessary.  The PSCU has allowed Questar Gas to record incremental operating costs to comply with this act as a regulatory asset until the next rate case.

Based on clarification from the FERC, Questar Gas believes that it is not an energy or marketing affiliate of Questar Pipeline under FERC Order No. 2004.  Questar Gas, in common with other Questar companies, has adopted new procedures to comply with the order.

Corporate and Other Operations

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

In June 2004 Questar reorganized its information-technology services, resulting in a staff reduction. Severance costs were approximately $600,000 in the first nine months of 2004.

Consolidated Results After Operating Income

Earnings from unconsolidated affiliates

Rendezvous income increased in the 2004 periods due to higher throughput. Gas Management is a 50% owner in Rendezvous, which provides gas-gathering services for the Pinedale and Jonah producing areas of western Wyoming.

Debt expense

Lower debt balances and long-term interest rates resulted in lower debt expense in 2004. In 2004 and 2003 Questar Gas replaced higher-cost fixed-rate debt with lower-cost fixed- and floating-rate debt. Market Resources reduced long-term debt by $55 million in 2004.

Income taxes

The effective combined federal and state income tax rate for the first nine months was 37.2% in 2004 and 37.1% in 2003.

Accounting change

On January 1, 2003, the Company adopted a new accounting standard, SFAS 143, “Accounting for Asset Retirement Obligations,” and recorded a cumulative effect that reduced net income by $5.6 million or $0.07 per diluted common share.

Liquidity and Capital Resources

Operating Activities

Net cash provided from operating activities increased 11% in 2004 compared with 2003 due to increased income and noncash adjustments to income. However a $63.9 million hedging collateral deposit was made in response to higher sales prices for gas and oil in 2004.

Investing Activities

A comparison of capital expenditures for the first nine months of 2004 and 2003 plus the budgeted amount for calendar years 2004 and 2005 is presented below.  Corporate and other operations include $25 million fro as yet unidentified projects in 2005 in the operating subsidiaries.

Financing Activities

Net cash flow provided from operating activities was more than sufficient to fund capital expenditures and pay dividends in the first nine months of 2004. The excess cash flow was used to repay debt. As a result total debt was 44% of total capital at September 30, 2004. In 2004 Market Resources repaid $55 million of long-term debt and Questar Gas repaid $17 million of long-term debt.

Short-term debt at September 30, 2004 and 2003 was comprised of commercial paper. The average interest rate was 1.8% in 2004 and 1.2% in 2003. The Company's lines-of-credit capacity is $210 million beginning October 1, 2004.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

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

Commodity-Price Risk Management

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

Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. Natural gas- and oil-price hedging support Market Resources’ rate of return and cash flow targets and protect earnings from downward movements in commodity prices. The volume of hedged production and the mix of derivative instruments are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by the Finance and Audit Committee of the Board of Directors. Market Resources may hedge up to 100% of forecast nonregulated production from proved-developed reserves when prices meet earnings and cash flow objectives. 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 or equit y NGL.

Hedges are matched to equity gas and oil production, thus qualifying as cash-flow hedges under the accounting provisions of SFAS 133 as amended and interpreted. Gas hedges are structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. The portion of hedges no longer deemed effective is immediately recognized in the income statement. The ineffective portion of hedges was not significant in 2004 and 2003.

As of September 30, 2004, approximately 67.9 bcf of forecast full-year 2004 gas production was 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.

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 varies depending on the credit rating assigned to Market Resources’ debt. Market Resources’ current ratings support counterparty credit ranging from $5 million to $20 million. 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. Questar maintains lines of credit to cover potential collateral calls.  Collateral required at September 30, 2004, was $63.9 million held in interest-bearing accounts.  In October 2004, Market Resources requested an increase in the limitation to $200 million and received approval from its bank group. The collateral calls have not had a material impact on creditworthiness, cash flow or liquidity of Questar or Market Resources.

A summary of Market Resources’ hedging positions for equity production as of September 30, 2004, is shown below. Prices are net to the well. Currently all hedges are fixed-price swaps with creditworthy counterparties, which allows Market Resources 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 148.3 MMdth of gas and 1.5 MMbbl of oil as of September 30, 2004. A year earlier Market Resources’ hedging contracts covered 121.9 MMdth of natural gas and 276,000 bbl of oil. Market Resources does not hedge the price of equity NGL.

The following table summarizes changes in the fair value of hedging contracts from December 31, 2003, to September 30, 2004.

A table of the net fair value of gas-hedging contracts as of September 30, 2004, is shown below. About 76% of the fair value of all contracts will settle and be reclassified from other comprehensive income in the next 12 months.

The following table shows sensitivity of the mark-to-market valuation of gas and oil price-hedging contracts to changes in the market price of gas and oil.

Interest-Rate Risk Management

As of September 30, 2004, Questar had $933.2 million of fixed-rate long-term debt and no variable-rate long-term debt.

Recent Accounting Pronouncements

On October 13, 2004, the Financial Accounting Standards Board (“FASB”) concluded that all companies would be required to measure costs for stock-based awards using estimated fair value on the date of grant.  SFAS 123R “Share-Based Payments” applies to all awards granted, modified or settled for periods beginning July 1, 2005.  Questar issues stock options and restricted shares to employees and non-employee directors.  Currently Questar accounts for stock options under the intrinsic-value method where no expense is recorded.  SFAS 123R will change this treatment and require recognition of costs in the consolidated statement of income.  Questar has measured the impact and disclosed the pro forma effect in Note 5 of this report.  FASB expects to issue a final version of SFAS 123R by December, 2004.

In September 2004 the Emerging Issues Task Force (“EITF”) of the FASB proposed 04-9, "Accounting for Suspended Well Costs."  SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”, requires the capitalization of costs of drilling exploratory wells pending determination of whether the well has found proved reserves. The capitalized costs become part of the entity's wells, equipment, and facilities if the well successfully located proved reserves. However, if the well has not found proved reserves, the capitalized costs of drilling the well are expensed, net of any salvage value. Questions have arisen in practice about the application of this guidance due to changes in gas- and oil-exploration processes, lifecycles and land-access regulations. The issue is whether there are circumstances that would permit the continued capitaliz ation of exploratory well costs beyond the one-year limit specified in SFAS 19 other than when additional exploration wells are necessary to justify major capital expenditures and those wells are underway or firmly planned for the near future.  A ruling from the EITF is expected in the fourth quarter of 2004.  The Company has not completed an evaluation of the financial effects of EITF 04-9.

Item 4.

Controls and Procedures.

a.

Evaluation of Disclosure Controls and Procedures.  The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-14(c) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”).  Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the Company’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company, including its consolidated subsidiaries, required to be included in the Company’s reports filed or submitted under the Exchange Act.

b.

Changes in Internal Controls.  Since the Evaluation Date, there have not been any significant changes in the Company’s internal controls in other factors that could significantly affect such controls.

PART II

OTHER INFORMATION

Item 1.

Legal Proceedings.

a.

See Note 3 in the Notes accompanying the Company’s Consolidated Financial Statements under Item 1.  Financial Statements in Part I of this report for a discussion of the regulatory proceedings involving Questar Gas’s processing costs.  These proceedings have been reviewed in the Company’s periodic reports filed since August 1, 2003, most recently in the Current Report on Form 8-K dated August 30, 2004.

b.

During the third quarter of 2004, Questar E&P settled one of three pending cases involving the Beaver Gas Pipeline System located in western Oklahoma.  It paid $500,000 to settle the claim brought by the Oklahoma State Tax Commission in State of Oklahoma ex rel. State Tax Commission v. Questar Exploration and Production Co., No. W-2004-10 (Dist. Ct. Okla).  The Tax Commission claimed that Questar E&P owed additional production taxes to reflect royalty class action settlements involving the Beaver system and another pipeline system formerly owned by Questar E&P.  See, Item 3. Legal Proceedings in Part I of the Company’s Annual Report on Form 10-K for 2003 for a description of two other pending cases involving the Beaver system.

Item 2.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities.

The following table sets forth the Company’s purchases of common stock registered under Section 12 of the Exchange Act that occurred during the quarter ended September 30, 2004:

*The numbers include any shares purchased in conjunction with tax payment elections under the Company’s Long-term Stock Incentive Plan.  They exclude any fractional shares purchased from terminating participants in Questar’s Dividend Reinvestment and Stock Purchase Plan, any shares of restricted stock forfeited when failing to satisfy vesting conditions, and any shares delivered or attested to when exercising stock options.

Item 6.

Exhibits and Reports on Form 8-K.

a.

The following exhibits are being filed as part of this report:

Exhibit No.

Exhibit

     12.

Ratio of earnings to fixed charges.

     31.1.

Certification signed by Keith O. Rattie, Questar's Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

     31.2.

Certification signed by S. E. Parks, Questar's Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

     32.

Certification signed by Keith O. Rattie and S. E. Parks, Questar's Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

b.

During the quarter, Questar filed the following Current Reports on Form 8-K:  Current Report dated July 28, 2004, filing a copy of the Company’s earnings release for the period ended June 30, 2004 and Current Report dated August 30, 2004, disclosing an order issued by the PSCU in Questar Gas’s processing cost case.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

QUESTAR CORPORATION

(Registrant)

November 8, 2004

/s/Keith O. Rattie__________________

         Date

Keith O. Rattie, Chairman of the Board,

President and Chief Executive Officer

November 8, 2004

/s/S. E. Parks_______________________

         Date

S. E. Parks, Senior Vice President and

Chief Financial Officer

Exhibits List

Exhibits

     12.

Ratio of earnings to fixed charges.

     31.1.

Certification signed by Keith O. Rattie, Questar's Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

     31.2.

Certification signed by S. E. Parks, Questar's Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

     32.

Certification signed by Keith O. Rattie and S. E. Parks, Questar's Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit No. 31.1.

CERTIFICATION

I, Keith O. Rattie, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Questar Corporation.

2.

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

3.

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

4.

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

a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c)

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

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

a)

all significant deficiencies in the design or operation of internal controls that could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls;

6.

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

November 8, 2004

/s/Keith O. Rattie_____________________

         Date

Keith O. Rattie

Chairman, President and Chief Executive Officer

Exhibit No. 31.2.

CERTIFICATION

I, S. E. Parks, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Questar Corporation.

2.

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

3.

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

4.

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

a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c)

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

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

a)

all significant deficiencies in the design or operation of internal controls that could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls;

6.

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

November 8, 2004

/s/S. E. Parks___________________

          Date

S. E. Parks

Senior Vice President and

Chief Financial Officer

Exhibit No. 32.

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTON 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Questar Corporation (the "Company") on Form

10-Q for the period ending September 30, 2004, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Keith O. Rattie, Chairman, President and Chief Executive Officer of the Company, and S. E. Parks, Senior Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1)

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

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

QUESTAR CORPORATION

November 8, 2004

/s/Keith O. Rattie_______________________

          Date

Keith O. Rattie

Chairman, President and Chief Executive Officer

November 8, 2004

/s/S. E. Parks___________________________

          Date

S. E. Parks

Senior Vice President and Chief Financial Officer