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

Form 10-Q

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED March 31, 2004.
	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 Number 1-8796

QUESTAR CORPORATION
(Exact name of registrant as specified in its charter)
	State of Utah (State or other jurisdiction of incorporation or organization)	87-0407509 (IRS Employer Identification Number)
	P.O. Box 45433 180 East 100 South Salt Lake City, Utah (Address of principal executive offices)	84145-0433 (Zip code)

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

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

Yes   [X]	No   [  ]
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Class	Outstanding as of April 30, 2004
Common Stock, without par value with attached Common Stock Purchase Rights	83,779,086 Shares

Questar Corporation

Form 10-Q for the Quarterly Period Ended March 31, 2004

TABLE OF CONTENTS

Page

PART I.

FINANCIAL INFORMATION

Item 1.

Financial Statements

Item 2.

Item 3.

Item 4.

PART II.

OTHER INFORMATION

Item 5.

Item 6.

#

Glossary of Commonly Used Terms

bbl

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

basis

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

bcf

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

bcfe

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

Btu

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

cash flow hedge

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

development well

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

dew point

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

dry hole

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

dth

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

exploratory well

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

futures contract

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

gross

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

hedging

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

Mbbl

One thousand barrels.

Mcf

One thousand cubic feet.

Mcfe

One thousand cubic feet of natural gas equivalents.

Mdth

One thousand decatherms.

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 the 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: changes in general economic conditions; changes in gas and oil prices and changes in estimated quantities of gas and oil reserves; 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; rate of inflation and interest rates; assumptions used in business combinations; weather and natural disasters; the effect of environmental and other regulation; effects of endangered or threatened species regulations; changes in customers' credit ratings; competition from other forms of energy, other pipelines and storage facilities; the effect of accounting policies issued periodically by accounting standard-setting bodies; terrorist attacks or acts of war; changes in the business or financial condition of the Company; and changes in credit ratings for Questar and/or its subsidiaries.

PART 1. FINANCIAL INFORMATION
Item 1. Financial Statements
QUESTAR CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	3 Months Ended		12 Months Ended
	March 31,		March 31,
	2004	2003	2004	2003
	(in thousands, except per share amounts)
REVENUES
Market Resources	$  234,054	$   213,193	$  772,363	$   610,511
Questar Pipeline	18,013	18,136	74,858	71,909
Questar Gas	306,879	234,514	691,156	567,391
Corporate and other operations	4,670	3,961	18,623	18,127
TOTAL REVENUES	563,616	469,804	1,557,000	1,267,938
OPERATING EXPENSES
Cost of natural gas and other products sold	266,259	201,341	607,359	418,555
Operating and maintenance	78,429	73,837	288,858	284,124
Depreciation, depletion and amortization	52,269	47,938	196,713	187,583
Distribution rate-refund obligation	1,490		26,429
Exploration	1,087	1,170	4,415	4,508
Abandonment and impairment of gas,
oil and other properties	4,406	483	8,074	11,360
Production and other taxes	22,886	17,160	76,407	49,943
TOTAL OPERATING EXPENSES	426,826	341,929	1,208,255	956,073
OPERATING INCOME	136,790	127,875	348,745	311,865
Interest and other income	1,824	2,593	6,666	51,854
Earnings from unconsolidated affiliates	1,310	1,036	5,282	12,156
Minority interest	(270)	77	(125)	408
Debt expense	(17,516)	(18,916)	(69,336)	(80,001)
INCOME BEFORE INCOME TAXES
AND CUMULATIVE EFFECT	122,138	112,665	291,232	296,282
Income taxes	46,005	42,463	106,105	105,339
INCOME BEFORE CUMULATIVE EFFECT	76,133	70,202	185,127	190,943
Cumulative effect of accounting change
for asset-retirement obligations, net of
income taxes of $3,331		(5,580)		(5,580)
NET INCOME	$   76,133	$    64,622	$   185,127	$   185,363
BASIC EARNINGS PER COMMON SHARE
Income before cumulative effect	$       0.91	$      0.86	$         2.22	$        2.33
Cumulative effect		(0.07)		(0.07)
Net income	$       0.91	$      0.79	$         2.22	$        2.26
DILUTED EARNINGS PER COMMON SHARE
Income before cumulative effect	$       0.89	$      0.84	$         2.18	$        2.30
Cumulative effect		(0.07)		(0.07)
Net income	$       0.89	$      0.77	$         2.18	$        2.23

PART 1. FINANCIAL INFORMATION – Continued
Item 1. Financial Statements
QUESTAR CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	3 Months Ended		12 Months Ended
	March 31,		March 31,
	2004	2003	2004	2003
	(in thousands, except per share amounts)
Weighted average common shares outstanding
Used in basic calculation	83,374	82,222	83,143	81,972
Used in diluted calculation	85,168	83,453	84,776	82,903
Dividends per common share	$       0.205	$     0.185	$         0.80	$      0.73
See notes accompanying consolidated financial statements

QUESTAR CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	March 31,			December 31,
	2004	2003		2003
	(Unaudited)
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents			$     41,475	$     13,905
Accounts receivable, net	$  218,639		211,606	199,378
Unbilled gas accounts receivable	24,431		26,107	49,722
Hedging collateral deposits	11,600		9,300	9,100
Fair value of hedging contracts	3,193		3,058	3,861
Inventories, at lower of average cost or market
Gas and oil in storage	19,703		20,173	40,305
Materials and supplies	13,545		11,295	12,184
Purchased-gas adjustments	14,112			552
Prepaid expenses and other	17,977		9,629	16,356
Deferred income taxes – current			7,865
Total current assets	323,200		340,508	345,363
Property, plant and equipment	4,545,882		4,271,556	4,502,795
Less accumulated depreciation, depletion
and amortization	1,781,301		1,631,909	1,734,266
Net property, plant and equipment	2,764,581		2,639,647	2,768,529
Investment in unconsolidated affiliates	37,559		22,022	36,393
Goodwill	71,260		71,133	71,260
Intangible pension asset	14,652		16,911	14,652
Regulatory and other assets	69,565		62,913	72,858
	$3,280,817		$3,153,134	$3,309,055
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Checks in excess of cash balances	$       4,086
Short-term debt	34,000			$   105,500
Accounts payable and accrued expenses	275,883		$  240,626	269,745
Fair value of hedging contracts	76,851		47,605	52,959
Purchased-gas adjustments			20,698
Deferred income taxes-current	5,362			210
Current portion of long-term debt	11		64,010	55,011
Total current liabilities	396,193		372,939	483,425
Long-term debt, less current portion	950,191		1,060,183	950,189
Deferred income taxes and investment-tax credits	447,786		377,914	447,005
Other long-term liabilities	71,474		56,238	66,332
Asset-retirement obligations	62,722		57,641	61,358
Pension liability	29,448		38,726	31,617
Minority interest	7,817		9,726	7,864
COMMON SHAREHOLDERS’ EQUITY
Common stock	334,535		304,832	324,783
Retained earnings	1,036,774		918,113	977,780
Other comprehensive loss	(56,123)		(43,178)	(41,298)
Total common shareholders’ equity	1,315,186		1,179,767	1,261,265
	$3,280,817		$3,153,134	$3,309,055
See notes accompanying consolidated financial statements

QUESTAR CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	3 Months Ended
	March 31,
	2004	2003
	(in thousands)
OPERATING ACTIVITIES
Net income	$  76,133	$    64,622
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	54,724	49,781
Deferred income taxes and investment tax credits	14,867	4,814
Amortization of restricted stock	576
Abandonment and impairment of gas,
oil and other properties	4,406	483
(Income) loss from unconsolidated affiliates,
net of cash distributions	(1,166)	1,595
Net gain from asset sales		(107)
Minority interest and other	270	(178)
Cumulative effect of accounting change		5,580
	149,810	126,590
Changes in operating assets and liabilities	21,807	3,620
NET CASH PROVIDED FROM OPERATING ACTIVITIES	171,617	130,210
INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(53,882)	(35,565)
Other investments		(16)
Total capital expenditures	(53,882)	(35,581)
Proceeds from disposition of assets	895	5,869
NET CASH USED IN INVESTING ACTIVITIES	(52,987)	(29,712)
FINANCING ACTIVITIES
Common stock issued	9,146	6,388
Common stock repurchased	(1,813)	(1,713)
Long-term debt issued		110,000
Long-term debt repaid	(54,998)	(130,997)
Change in short-term debt	(71,500)	(49,000)
Checks in excess of cash balances	4,086
Dividends paid	(17,139)	(15,211)
Other	(317)	(131)
NET CASH USED IN FINANCING ACTIVITIES	(132,535)	(80,664)
Change in cash and cash equivalents	(13,905)	19,834
Beginning cash and cash equivalents	13,905	21,641
Ending cash and cash equivalents	$             -	$    41,475
See notes accompanying consolidated financial statements

QUESTAR CORPORATION

NOTES ACCOMPANYING CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2004

(Unaudited)

Note 1 – Basis of Presentation of Interim Financial Statements

The accompanying 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 interim financial statements reflect all normal, recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the results of operations for the interim periods presented. The preparation of financial statements in conformity with accounting principles generally accepted (“GAAP”) 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 estimates. All significant intercompany accounts and transactions were eliminated in consolidation.

The results of operations for the three- and twelve-month periods ended March 31 are not necessarily indicative of the results that may be expected for the year ending December 31, 2004, due to the seasonal nature of the gas distribution business. The impact of abnormal weather on gas distribution earnings is significantly reduced by the operation of a weather-normalization adjustment. The straight fixed-variable rate design, which allows for recovery of substantially all fixed costs in the demand or reservation charges, reduces the earnings impact of weather conditions on gas transportation and storage operations. Interim financial statements do not include all of the information and notes required by GAAP for audited annual 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, that was filed by Questar.

Note 2 – Asset-Retirement Obligations

On January 1, 2003 Questar adopted Statement of Financial Accounting Standards (“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. Asset-retirement obligations are adjusted to present value each period through an accretion process using a credit-adjusted risk-free interest rate.  Both the accretion expense associated with the liability and the depreciation associated with the capitalized abandonment costs are non-cash expenses until the time that the asset is retired.

Changes in asset-retirement obligations were as follows.

	2004	2003
	(in thousands)
Balance at January 1,	$61,358	$56,493
Accretion	939	908
Additions	427	240
Properties sold	22
Retirements	(24)
Balance at March 31,	$62,722	$57,641

Note 3 – Questar Gas Processing Dispute

On August 1, 2003 the Utah Supreme Court issued an order reversing a decision made by the Public Service Commission of Utah (“PSCU”) in August of 2000 concerning certain processing costs incurred by Questar Gas Company (“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 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 liability for a potential refund to gas-distribution customers. The liability of $26.4 million, including $1.5 million recorded in the first quarter of 2004, reflects revenue received for processing costs from June 1999 through March 2004.  The court order did not have a material impact on the creditworthiness, cash flow or liquidity of Questar or Questar Gas.  Questar Gas has requested ongoing rate coverage for gas-processing costs in its gas-cost pass-through filings and is currently collecting these ongoing costs in rates. Questar Gas will continue to record a liability for the potential refund of the ongoing gas-processing costs until the issue is decided by the PSCU.

In January 2004 the Committee filed a petition for extraordinary relief with the Utah Supreme Court. The Utah Supreme Court denied the petition in March 2004, clearing the way for the PSCU to reopen proceedings to review the prudence of Questar Gas’s decision-making on gas processing.  Hearings are scheduled for the end of May 2004.

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.

In the first quarter of 2004, Questar issued 488,000 shares under the terms of the Long-Term Stock Incentive Plan, the Dividend Reinvestment and Stock Purchase Plan, and the Employee Investment Plan.

	3 Months Ended		12 Months Ended
	March 31,		March 31,
	2004	2003	2004	2003
	(in thousands)
Weighted-average basic common shares outstanding	83,374	82,222	83,143	81,972
Potential number of shares issuable from exercising
stock options	1,794	1,231	1,633	931
Weighted-average diluted common shares outstanding	85,168	83,453	84,776	82,903

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.” No compensation expense is recorded for stock options granted because the exercise price of those options is equal to the market price on the date of grant. The table below shows pro forma income as if the options were expensed under the fair-value based method.

	3 Months Ended		12 Months Ended
	March 31,		March 31,
	2004	2003	2004		2003
	(in thousands)
Net income, as reported	$76,133	$64,622	$185,127	$185,363
Additional stock-based compensation expense     determined under fair-value based method	(652)	(1,363)	(4,566)	(5,188)
Pro forma net income	$75,481	$63,259	$180,561	$180,175
Earnings per share
Basic, as reported	$0.91	$0.79	$2.22	$2.26
Basic, pro forma	0.91	0.77	2.17	2.20
Diluted, as reported	0.89	0.77	2.18	2.23
Diluted, pro forma	0.89	0.76	2.13	2.17

The Company issues restricted shares to employees with various vesting periods. Expense is recognized over the vesting periods calculated on share value on the grant date. Amortization of restricted share expense was $576,000 in the first quarter of 2004.

Note 6 – Operations by Line of Business

	3 Months Ended		12 Months Ended
	March 31,		March 31,
	2004	2003	2004	2003
	(in thousands)
REVENUES FROM UNAFFILIATED CUSTOMERS
Market Resources	$234,054	$213,193	$   772,363	$   610,511
Questar Pipeline	18,013	18,136	74,858	71,909
Questar Gas	306,879	234,514	691,156	567,391
Corporate and other operations	4,670	3,961	18,623	18,127
	$563,616	$469,804	$1,557,000	$1,267,938
REVENUES FROM AFFILIATED COMPANIES
Market Resources	$  34,357	$  26,449	$   125,414	$   105,125
Questar Pipeline	22,293	20,339	83,811	75,954
Questar Gas	1,137	889	2,452	2,264
Corporate and other operations	6,527	7,737	28,989	32,067
	$  64,314	$  55,414	$   240,666	$   215,410
OPERATING INCOME
Market Resources	$  69,323	$  59,557	$   220,111	$   161,338
Questar Pipeline	18,287	18,285	71,098	68,729
Questar Gas	47,899	48,706	50,578	74,170
Corporate and other operations	1,281	1,327	6,958	7,628
	$136,790	$127,875	$   348,745	$   311,865
INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGE
Market Resources	$  40,255	$  34,049	$   127,309	$   114,376
Questar Pipeline	8,113	8,053	30,362	33,244
Questar Gas	26,311	26,004	20,823	34,237
Corporate and other operations	1,454	2,096	6,633	9,086
	$  76,133	$  70,202	$   185,127	$   190,943
NET INCOME
Market Resources	$  40,255	$  28,936	$   127,309	$   109,263
Questar Pipeline	8,113	7,920	30,362	33,111
Questar Gas	26,311	25,670	20,823	33,903
Corporate and other operations	1,454	2,096	6,633	9,086
	$  76,133	$  64,622	$   185,127	$   185,363

Note 7 – Employee Benefits

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 by the 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 $16.2 million. Components of pension expense included in the determination of quarterly net income are listed below.

Pension Expense

	3 Months Ended
	March 31,
	2004	2003
	(in thousands)
Service cost	$2,140	$1,902
Interest cost	4,840	4,572
Expected return on plan assets	(4,674)	(4,440)
Prior service and other costs	481	481
Recognized net-actuarial loss	541	226
Amortization of early-retirement costs	719	810
Pension expense	$4,047	$3,551

Expense of Postretirement Benefits Other than Pensions

The Company currently estimates a $6.8 million expense for postretirement benefits in 2004. Expense components for the first quarter are listed below.

	3 Months Ended
	March 31,
	2004	2003
	(in thousands)
Service cost	$   221	$   197
Interest cost	1,317	1,326
Expected return on plan assets	(653)	(651)
Prior service and other costs	470	469
Recognized net-actuarial loss	142	120
Amortization of early-retirement costs	200	200
Postretirement benefits other than pension expense	$1,697	$1,661

Questar deferred recognizing the impact of the Medicare Prescription Drug, Improvement and Modernization Act (“MMA”) until finalization of accounting rules expected sometime during the second quarter of 2004. Questar will be required to show the effect of MMA in the second half of 2004. The MMA must be treated as an actuarial gain and not a prior service benefit; therefore, it will be amortized over future periods.

Note 8 – Financing

On March 19, 2004 Questar Market Resources (“Market Resources”) completed a $200 million  credit facility with a consortium of banks that replaced an existing facility due to expire 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 of natural gas, and have no debt obligations with third-party lenders. The principal affiliates and Questar's ownership percentage as of March 31, 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.

	3 Months Ended
	March 31,
	2004	2003
	(in thousands)
Revenues	$4,376	$3,667
Operating income	2,767	2,082
Income before income taxes	2,772	2,096

Note 10 – Comprehensive Income

Comprehensive income is the sum of net income as reported in the Consolidated Statements of Income and other comprehensive transactions reported in Common Shareholders' Equity. Other comprehensive transactions include changes in the market value of gas or oil-price derivatives. These reported results are not current income or loss but represent changes in the fair values of the derivatives. 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.

	3 Months Ended
	March 31,
	2004	2003
	(in thousands)
Net income	$ 76,133	$ 64,622
Other comprehensive loss
Unrealized loss on hedging transactions	(23,760)	(23,188)
Income taxes	8,935	8,669
Net other comprehensive loss	(14,825)	(14,519)
Total comprehensive income	$ 61,308	$ 50,103

Note 11 – Reclassifications

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

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

March 31, 2004

(Unaudited)

Results of Operations

Questar Corporation (“Questar” or “the Company”) is a natural gas-focused energy company that conducts operations through two groups, Questar Market Resources (“Market Resources”) and Questar Regulated Services (“Regulated Services”). Market Resources, through various subsidiaries, engages in gas and oil exploration, 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.

SUMMARY

Questar reported first quarter 2004 net income of $76.1 million or $0.89 per diluted share compared to $64.6 million or $0.77 per share for the first quarter of 2003. The 2003 quarter was reduced by $5.6 million or $0.07 per share for an accounting change. Following is a comparison of net income by line of business.

	Net Income
	3 Months Ended March 31,		Increase	Percentage
	2004	2003	(Decrease)	Change
	(in thousands, except per share amounts)
Market Resources	$40,255	$28,936	$11,319	39%
Questar Pipeline	8,113	7,920	193	2%
Questar Gas	26,311	25,670	641	2%
Corporate and other operations	1,454	2,096	(642)	(31%)
Net income	$76,133	$64,622	$11,511	18%
Earnings per diluted common share	$0.89	$0.77	$0.12	16%

Market Resources first quarter 2004 net income increased 39% over the first quarter of 2003 because of an 8% increase in nonregulated production, a 16% increase in realized commodity prices, additions to Wexpro's investment base and increased gas-gathering throughput. An accounting change reduced earnings in the first quarter of 2003 by $5.1 million.

Questar Pipeline net income increased 2% because of pipeline system expansions in response to growing regional natural gas production. Higher operating expenses and lower capitalization of construction-related costs partially offset increased revenues. An accounting change reduced first quarter 2003 net income by $133,000.

Questar Gas net income increased 2% driven by a 3% increase in customers that more than offset a 5% decline in usage per customer and a $1.5 million pretax expense related to a gas processing dispute. An accounting change reduced first quarter 2003 earnings by $334,000.

Net income from corporate and other operations decreased 31% in the first quarter of 2004 compared to the same quarter of 2003 because of reduced cost-based services provided to affiliated customers.

Market Resources

Market Resources is a wholly-owned subsidiary of Questar. 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”) develops 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 owns and operates an underground gas-storage reservoir. Following is a summary of Market Resources’ financial results and operating information.

	3 Months Ended		12 Months Ended
	March 31,		March 31,
	2004	2003	2004	2003
FINANCIAL RESULTS - (in thousands)
Revenues
From unaffiliated customers	$234,054	$213,193	$772,363	$610,511
From affiliates	34,357	26,449	125,414	105,125
Total revenues	$268,411	$239,642	$897,777	$715,636
Operating income	$  69,323	$  59,557	$220,111	$161,338
Income before cumulative effect	$  40,255	$  34,049	$127,309	$114,376
Cumulative effect of accounting change		(5,113)		(5,113)
Net income	$  40,255	$  28,936	$127,309	$109,263
OPERATING STATISTICS
Nonregulated production volumes
Natural gas (MMcf)	21,888	20,104	80,595	79,771
Oil and natural gas liquids (Mbbl)	587	572	2,339	2,589
Total production (bcfe)	25.4	23.5	94.6	95.3
Average daily production (MMcfe)	279	262	259	261
Average commodity prices, net to the well
Average realized sales price (including hedges)
Natural gas (per Mcf)	$4.05	$3.52	$3.76	$2.86
Oil and natural gas liquids (per bbl)	29.46	24.71	24.59	21.79
Average sales price (without hedges)
Natural gas (per Mcf)	$4.72	$4.21	$4.30	$2.76
Oil and natural gas liquids (per bbl)	31.85	31.14	28.67	25.96
Wexpro investment base at March 31, net of
depreciation and deferred income taxes     (millions)	$169.0	$159.3
Natural gas and oil marketing volumes     (Mdthe)	21,855	21,311	80,740	82,662
Natural gas gathering volumes (Mdth)
For unaffiliated customers	34,294	28,325	120,742	111,905
For Questar Gas	9,757	11,583	39,742	40,045
For other affiliated customers	14,558	12,092	48,617	42,841
Total gathering	58,609	52,000	209,101	194,791
Gathering revenue (per dth)	$0.21	$0.19	$0.20	$0.17

Comparison of the first quarter and 12 months ended March 2004 with March 2003 periods.

Market Resources

For the first three months of 2004, Market Resources net income totaled $40.3 million compared with $28.9 million for the year earlier period, a 39% increase as revenue growth outpaced an increase in expenses.  Market Resources recorded operating income of $69.3 million in the current quarter versus $59.6 million in 2003, a 16% increase, due primarily to improved margins at Questar E&P and Gas Management.  For the first quarter of 2004 Market Resources had revenues of $268.4 million compared to $239.6 million for the year earlier period.  Revenue growth was driven by an 8% increase in nonregulated production volumes (nonregulated volumes exclude Wexpro “cost-of-service” production) and 16% higher realized commodity prices at Questar E&P, additions to the investment base at Wexpro, and increased throughput and higher fees at Gas Management.  Expenses for the current quarter were $199 million, 11% higher than the 2003 quarter.  The increase was due to increased abandonment expense, production taxes, lease operating expense and depreciation, depletion and amortization.

Questar E&P

For the first quarter of 2004, Questar E&P earned $25.2 million compared with $16 million for the same period in 2003. Higher profits were driven by increased nonregulated production and higher realized natural gas, oil and NGL prices.

Questar E&P’s production for the quarter was 25.4 bcfe compared with 23.5 bcfe for the 2003 period, an 8% increase.  Production growth was driven by the accelerated pace of development drilling on the Pinedale Anticline in western Wyoming. Nonregulated first quarter volumes from Pinedale increased 104% to 6.1 bcfe versus 3.0 bcfe a year earlier. Market Resources had 76 producing wells at Pinedale in the 2004 quarter compared to 51 during the same period a year earlier. Midcontinent production also increased by 0.9 bcfe for the current quarter to 8.6 bcfe versus 7.7 bcfe in the 2003 period. Midcontinent growth was propelled by ongoing development drilling in the Hartshorne coal bed methane (“CBM”) project in the Arkoma Basin of eastern Oklahoma and increased development drilling on the Elm Grove properties in northwest Louisiana. Production increases were partially offset by a 2.1 bcfe decline in Uinta Basin volumes from 8.4 bcfe in the first quarter of 2003 to 6.3 bcfe in the 2004 quarter.  First quarter 2003 Uinta Basin gas production benefited from high initial flow rates from wells that were deliberately shut-in due to low Rockies gas prices during the second half of 2002. First quarter 2004 production from Rockies “Legacy” properties was flat at 4.4 bcfe compared to the first quarter 2003.  Legacy properties include all of Questar E&P’s Rocky Mountain producing properties exclusive of Pinedale and the Uinta Basin.

Increased production and higher realized prices for gas, oil and NGL were responsible for a 24% increase in revenues for the 12 months ended March 31, 2004, compared to the same period of 2003. Gas production was 1% higher in the 2004 period despite the sale of non-core assets during the second half of 2002. The majority of the asset sales took place in the fourth quarter of 2002; however, Rockies gas production increased 7% in the 2004 period. Nonregulated production by region is shown below.

	3 Months Ended		12 Months Ended
	March 31,		March 31,
	2004	2003	2004	2003
	(in bcfe)
Rocky Mountains
Pinedale Anticline	6.1	3.0	18.3	9.7
Uinta Basin	6.3	8.4	26.9	28.7
Rockies Legacy	4.4	4.4	16.6	19.8
Subtotal – Rocky Mountains	16.8	15.8	61.8	58.2
Midcontinent	8.6	7.7	32.8	32.2
Canada				4.9
Total – nonregulated production	25.4	23.5	94.6	95.3

Natural gas sales prices in Questar E&P’s core Rockies areas increased significantly in the first quarter of 2004 compared to a year ago. Midcontinent prices decreased slightly over the comparable period.  For the current quarter, average realized prices (including the effects of hedging) were $4.05 Mcf compared to $3.52 per Mcf for the same period in 2003, a 15% increase.  Average realized prices in the Rockies improved 30% from $3.02 per Mcf in the first quarter of 2003 to $3.94 per Mcf in 2004.  Approximately 66% of Questar E&P’s production came from properties located in the Rockies.  Rockies basis, the regional difference between Rockies prices and the reference Henry Hub price, returned to a more normal level of $0.75 per Mcf for the first quarter of 2004, compared to $2.85 per Mcf for the same period in 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 quarter.  Midcontinent average realized prices decreased 6% from $4.52 per Mcf in the first quarter of 2003 to $4.26 per Mcf in 2004.

	3 Months Ended March 31,		12 Months Ended March 31,
	2004	2003	2004	2003
	(per Mcf)
Average realized gas prices by region      (including hedges)
Rocky Mountains	$3.94	$3.02	$3.52	$2.39
Midcontinent	4.26	4.52	4.19	3.70
Canada				2.44
Volume weighted average	4.05	3.52	3.76	2.86

Realized oil and NGL prices also increased in the current quarter versus the year earlier period.  For the 2004 quarter realized oil and NGL prices averaged $29.46 bbl, compared with $24.71 per bbl in the first quarter of 2003, a 19% increase.

Approximately 83% of Questar E&P’s gas production in the first quarter of 2004 was hedged or pre-sold at an average price of $4.09 per Mcf net to the well (reflects adjustments for regional basis, gathering and processing costs, and gas quality) resulting in a $14.7 million reduction in revenue for the quarter compared to results if the entire volume had not been hedged and sold at prevailing market prices.  Market Resources also hedged or pre-sold approximately 29% percent of its oil production for the period at an average net-to-the-well price of $30.90 per bbl, which resulted in a reduction in revenues of $1.4 million for the period.  Market Resources may hedge up to 100 percent of its forecasted nonregulated production from proved developed reserves when commodity prices are attractive. Market Resources hedges production to lock in acceptable returns on invested capital and to protect cash flows and earnings from a decline in commodity prices.  

Since the end of 2003 Market Resources has taken advantage of higher natural gas and oil prices to add to its hedge positions in 2004, 2005 and 2006.  Market Resources’ current natural gas and oil hedges are summarized in Item 3 of this report.

Increased industry activity in core operating areas has increased drilling and completion costs.  Current drilling rig day-rates increased 10 to 15% in both the Rockies and Midcontinent regions and prices for steel tubular goods used for well casing increased 20 to 25% compared to prices during the first quarter of 2003. Costs of high-pressure pumping services and proppant used in fracture stimulation of tight gas-sand reservoirs have remained relatively flat versus the year earlier period.

Questar E&P’s overall cost structure for the first quarter of 2004 increased to $2.36 Mcfe compared to $2.19 per Mcfe for the year earlier period.  Lifting costs increased from $0.76 per Mcfe in the 2003 quarter to $0.89 in the 2004 quarter.  A $0.04 per Mcfe increase in lease operating costs coupled with a $0.09 per Mcfe increase in production taxes due to higher realized prices drove the increase in lifting costs.  Depreciation, depletion and amortization expense increased to $0.98 per Mcfe in the first quarter of 2004 compared to $0.93 per Mcfe a year earlier. General and administrative expenses increased to $0.27 per Mcfe in the current period versus $0.26 for the 2003 quarter.  For the first quarter of 2004 allocated interest decreased to $0.22 per Mcfe compared to $0.24 per Mcfe for the same period in 2003.  

Lifting costs increased by 18% on an Mcfe basis during the current 12-month period.  Increased production taxes as a result of higher prices more than offset a slight reduction in lease-operating expenses. The decrease in lease operating expense was driven primarily by the sale of higher operating cost non-core properties during the second half of 2002.  General and administrative costs rose slightly. Questar E&P’s cost structure is summarized in the following table.

	3 Months Ended March 31,		12 Months Ended March 31,
	2004	2003	2004	2003
	(per Mcfe)
Lease-operating expense	$0.48	$0.44	$0.50	$0.52
Production taxes	0.41	0.32	0.36	0.21
Lifting costs	0.89	0.76	0.86	0.73
Depreciation, depletion and amortization	0.98	0.93	0.97	0.92
General and administrative expense	0.27	0.26	0.29	0.26
Allocated-interest expense	0.22	0.24	0.22	0.27
Total	$2.36	$2.19	$2.34	$2.18

Market Resources continued limited winter drilling for a second year on the Pinedale Anticline in western Wyoming. Market Resources is drilling three wells from a single pad over the winter of 2003/2004 and will continue drilling activity from the pad through the remainder of 2004. Questar E&P and Wexpro have a combined 62% average working interest in 14,800 acres at Pinedale. Market Resources is funding a multi-year study of the impact of year-round drilling activity at Pinedale on wintering mule deer.  The study is being conducted by the Bureau of Land Management (“BLM”), Wyoming Game and Fish, the University of Wyoming, and other stakeholders.

Market Resources has also submitted a proposal to the BLM seeking a long-term exception to the current winter stipulations that restrict drilling activity at Pinedale during the November 15 through May 1 time period.  If accepted by the BLM Market Resources will be allowed to drill from three active pads with two drilling rigs per pad, starting in the winter of 2004/2005. Market Resources believes that year-round drilling from pads is the most efficient and environmentally responsible approach for development of its Pinedale acreage.  Market Resources’ current proposal for year-round drilling would shorten the anticipated development drilling period on its Pinedale acreage from 18 years to about 9 years.  Under the proposal, Market Resources would also drill multiple directional wells from single surface pads. Only nine additional surface disturbances would be required to fully develop Market Resources’ current Pinedale acreage, regardless of ultimate subsurface well spacing (current spacing is one well per 40 acres).  The resultant reduction in overall surface disturbance would be significant. Under the proposal drilling-related surface disturbance would be reduced to less than 500 acres compared with up to 1,500 acres allowed on Market Resources’ acreage under the current Pinedale Anticline Oil and Gas Development Project Environmental Impact Statement.  

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 current peak seasonal activities.  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.

Market Resources anticipates that the BLM will make a decision on its proposal in time for the 2004/2005 winter drilling season, but at this point the BLM’s response to Market Resources’ proposal cannot be predicted.  In the past certain groups have sued the BLM over granting Market Resources limited winter-long exceptions to winter stipulations at Pinedale.

Questar E&P has continued gas-focused development drilling on its Uinta Basin properties in eastern Utah. During the first quarter of 2004, Questar E&P had three rigs drilling Wasatch/Upper Mesaverde formation wells, compared to two rigs a year earlier. Questar E&P completed 15 gross Wasatch/Upper Mesaverde wells in the current quarter compared to 19 gross Wasatch wells a year earlier.  Most of Questar E&P’s recent Uinta Basin development wells have been drilled about 1,000 feet deeper to complete additional sandstone reservoirs in the Upper Mesaverde Formation. Recent results support earlier estimates of approximately 0.25 to 0.3 bcfe of gross incremental reserves in the Upper Mesaverde for $200,000 to $300,000 of gross incremental cost. At the end of the first quarter of 2004, Questar E&P had approximately 150 identified Wasatch/Upper Mesaverde gross development locations remaining in inventory on its acreage. As previously announced Uinta Basin production peaked last year and will likely continue to slowly decline as Questar E&P drills its remaining inventory of low-risk Wasatch/Upper Mesaverde Formation development wells.

At the end of the first quarter, Questar E&P had completed 40 gross horizontal wells at its company-operated Hartshorne CBM project in the Arkoma Basin of eastern Oklahoma. Program results to date show an average Hartshorne horizontal CBM well, with initial gross production of 450 Mcf per day and estimated gross ultimate recoverable reserves of 0.5 to 0.6 bcfe, costs about $450,000 to drill and complete. Net production from the Hartshorne CBM project was 11.5 MMcf per day at the end of the current quarter compared to less than 1 MMcf per day during the same period in 2003. Questar E&P plans to drill about 25 additional wells during the remainder of 2004.  Questar E&P has an average 71% working interest in about 24,000 acres in the Hartshorne CBM project with a total remaining inventory in the current project area of approximately 65 gross development locations based on current 160 acre spacing. In addition Questar E&P has identified approximately 30 additional Hartshorne CBM horizontal well locations on company acreage outside the current project area.   

At Elm Grove field in northwest Louisiana, Questar E&P continued infill development drilling activity on its company-operated acreage, completing 5 gross wells during the first quarter of 2004. Elm Grove wells, which target multiple stacked Cotton Valley and Hosston Formation sandstone reservoirs, average gross recoverable reserves of about 2 bcfe and cost approximately $1.3 million to drill and complete. Based on current reservoir engineering and well performance data, Questar E&P expects to develop most of its 11,500 gross (8,000 net) acres at Elm Grove on an average well spacing of about 40 acres. Questar E&P has identified 40 gross additional infill development locations at Elm Grove and a number of existing Cotton Valley Formation wells with shallower behind-pipe Hosston Formation re-completion opportunities.   

Wexpro

Wexpro net income for the first quarter of 2004 was $9 million, compared with $7.6 million for the same period in 2003, which is an 18% increase.  Wexpro manages and develops gas reserves on behalf of Questar Gas. Wexpro activities are governed by a long-standing agreement (Wexpro Agreement) with the States of Utah and Wyoming. Pursuant to the Wexpro Agreement, Wexpro produces gas on behalf of Questar Gas, recovers its costs and receives an after-tax return of approximately 19% on its net investment in commercial wells and related facilities – known as the investment base – adjusted for working capital, deferred taxes, and depreciation. Wexpro’s average investment base increased to $169 million in the current quarter, a 6% increase over the year earlier period.

Gas Gathering and Processing; Gas and Oil Marketing

Net income from gas gathering, processing and marketing operations increased 14% to $6 million in the first quarter of 2004 from $5.3 million in the 2003 period. Gathering volumes increased 6.6 MMdth to 58.6 MMdth for the current quarter primarily due to increased production from the Pinedale and Jonah fields in western Wyoming.  Earnings from Gas Management’s 50% interest in Rendezvous Gas Services increased from $626,000 in 2003 to $849,000 in 2004. Rendezvous provides gas gathering services for the Pinedale/Jonah producing areas.

Gas Management continues to develop opportunities to invest in additional gas gathering and processing and liquids-handling facilities to meet growing equity and third-party production volumes from the Pinedale and Jonah fields and other areas in western Wyoming and around Market Resources’ Uinta Basin producing properties in eastern Utah.

Energy Trading’s gross margins, gross revenues less the costs to purchase gas and oil, commitments to gas transportation contracts on interstate pipelines, and gas storage costs, declined to $5.9 million in the first quarter of 2004 versus $6.2 million for the year earlier period.  The decline was due primarily to losses from long-term transportation contracts that were above market rates for the quarter.  In addition Energy Trading’s natural gas storage trading margins during the first quarter of 2004 were negatively impacted by lower inter- and intra-month gas-price volatility compared to the year earlier period.  Prior to the May 2003 expansion of a major interstate pipeline that delivers Rockies gas to California, extreme volatility in Rockies gas prices created significant gas storage arbitrage opportunities and positively impacted the value of Energy Trading’s gas transportation contracts.

Questar Pipeline

Questar Pipeline – a wholly-owned subsidiary of Questar – provides interstate natural gas transmission, storage, processing and gathering services. Following is a summary of financial results and operating information.

	3 Months Ended		12 Months Ended
	March 31,		March 31,
	2004	2003	2004	2003
FINANCIAL RESULTS - (in thousands)
Revenues
From unaffiliated customers	$18,013	$18,136	$  74,858	$  71,909
From affiliates	22,293	20,339	83,811	75,954
Total revenues	$40,306	$38,475	$158,669	$147,863
Operating income	$18,287	$18,285	$  71,098	$  68,729
Income before cumulative effect	$  8,113	$  8,053	$  30,362	$  33,244
Cumulative effect of accounting change		(133)		(133)
Net income	$  8,113	$  7,920	$  30,362	$  33,111
OPERATING STATISTICS
Natural gas transportation volumes (Mdth)
For unaffiliated customers	53,734	65,516	244,317	258,183
For Questar Gas	49,876	39,532	116,064	99,879
For other affiliated customers	4,260	3,677	26,807	9,168
Total transportation	107,870	108,725	387,188	367,230
Transportation revenue (per dth)	$     0.25	$     0.23	$     0.27	$     0.27

Revenues

Natural gas transmission and storage revenues grew 5% in the first quarter of 2004 compared with the first quarter of 2003 and 7% in the 12 months ended March 31, 2004, compared with the year-earlier period. Following is a summary of major changes in Questar Pipeline’s revenues.

	Change in revenues
	First Quarter 2004 v. 2003	12 Months Ended March 31, 2004 v. 2003
	(in thousands)
New transportation contracts	$1,500	$  4,700
Expiration of prior transportation contracts	(100)	(1,600)
Eastern segment of Southern Trails in service
beginning June of 2002		4,300
Change in gas-processing revenues	100	1,400
Change in gathering revenues		100
Other	300	1,900
Increase	$1,800	$10,800

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.

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 March 31, 2004, Questar Pipeline had firm-transportation contracts of 1,647 Mdth per day compared with 1,655 Mdth per day as of December 31, 2003. The amounts include 80 Mdth per day capacity on the eastern segment of Southern Trails. 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. Questar Gas has contracted for 62% of firm-storage capacity at Clay Basin for terms extending from 2008 to 2019.

During first quarter 2004 Questar Pipeline signed long-term contracts to support a $54 million expansion of its central Utah transmission system. The expansion will add over 100 MMcf 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.

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.

Operating Expenses

Operating and maintenance expenses increased 6% in the first quarter of 2004 over the first quarter of 2003. Reduced construction activity and related capitalization of labor costs resulted in higher operating expenses in the 2004 period. In addition employee benefits, insurance and pipeline-inspection costs have increased.

Operating and maintenance expenses increased 8% in the 12 months ended March 31, 2004, over the year-earlier period. Higher expenses were due to increased maintenance and higher employee benefit, insurance and pipeline safety.

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

Questar Gas

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

	3 Months Ended		12 Months Ended
	March 31,		March 31,
	2004	2003	2004	2003
FINANCIAL RESULTS - (in thousands)
Revenues
From unaffiliated customers	$306,879	$234,514	$691,156	$567,391
From affiliates	1,137	889	2,452	2,264
Total revenues	308,016	235,403	693,608	569,655
Cost of natural gas sold	216,730	144,635	466,618	337,800
Margin	$  91,286	$ 90,768	$226,990	$231,855
Operating income	$  47,899	$ 48,706	$  50,578	$ 74,170
Income before cumulative effect	$  26,311	$ 26,004	$  20,823	$ 34,237
Cumulative effect of accounting change		(334)		(334)
Net income	$  26,311	$ 25,670	$  20,823	$ 33,903
OPERATING STATISTICS
Natural gas volumes (Mdth)
Residential and commercial sales	41,684	35,468	90,609	82,903
Industrial sales	3,014	3,227	9,400	10,516
Transportation for industrial customers	9,938	9,552	38,727	44,151
Total industrial	12,952	12,779	48,127	54,667
Total deliveries	54,636	48,247	138,736	137,570
Natural gas revenue (per dth)
Residential and commercial	$6.79	$6.08	$6.84	$6.01
Industrial sales	5.52	4.30	5.11	3.96
Transportation for industrial customers	0.19	0.19	0.19	0.16
Heating degree days
colder (warmer) than normal	13%	(11%)	4%	(8%)
Average temperature adjusted usage
per customer (dth)	49.3	52.1	116.1	118.6
Customers at March 31,
Residential and commercial	775,031	752,148
Industrial	1,235	1,286
Total	776,266	753,434

Revenues less cost of natural gas sold (margin)

Questar Gas’s margin increased by 1% in the first quarter of 2004 compared with the first quarter of 2003 and decreased 2% in the 12 months ended March 31, 2004, compared with the 12 months ended March 31, 2003. Following is a summary of major changes in Questar Gas’s margin.

	Change in Margin
	First Quarter 2004 v. 2003		12 Months Ended March 31, 2004 v. 2003
	(in thousands)
General rate case		$6,000
New customers	$2,500	6,500
Change in usage per customer	(4,200)	(3,800)
Lower customer contribution revenues		(9,700)
2002 recovery of gas-processing costs		(3,800)
Recovery of gas-cost portion of bad-debt costs	600	1,000
Other	1,600	(1,100)
Increase (decrease)	$500	($4,900)

Effective December 30, 2002 the Public Service Commission of Utah (“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 March 31, 2004 Questar Gas was serving 776,266 customers. Customer growth remained above national averages at 3% over the prior year. Housing construction in Utah remained strong, driven by low mortgage-interest rates. Usage per customer, adjusted for normal temperatures, decreased 5% in the first quarter of 2004 compared with the 2003 first quarter and 2% for the 12 month period ended March 31, 2004 compared with the 2003 period.  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 13% colder than normal in the first quarter of 2004 compared with 11% warmer than normal in the first quarter of 2003. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations.

Questar Gas’s results for the 12 months ended March 31, 2003, 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, as discussed below.

Questar Gas’s results for the 12 months ended March 31, 2003, also included revenues of $9.7 million due to upfront contributions from customers. 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 and general rates were increased to make up for the change in revenues.

Industrial deliveries increased 1% in the first quarter of 2004 compared with the first quarter of 2003. Industrial deliveries decreased 12% in the 12 months ended March 31, 2004, compared with the same period ended March 31, 2003, as a result of lower power-generation requirements.

Operating Expenses

Operating and maintenance expenses were flat in the first quarter of 2004 compared with the first quarter of 2003. Lower information technology and labor costs offset higher contracted services and bad-debt costs. Operating and maintenance expenses decreased 7% in the 12 months ended March 31, 2004, compared with the 12 months ended March 31, 2003, because of lower information technology and bad-debt costs.

The Utah Supreme Court in August 2003 reversed earlier 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 Btu content of natural gas entering parts of Questar Gas’s system has been declining over the past decade. Processing provides a multi-year transition period during which customers will be required to have their appliances adjusted to ensure safe and efficient operation. 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 and an additional $1.5 million liability in the first quarter of 2004. The liability reflects a potential refund of gas processing costs collected in rates from June 1999 through March 2004 plus interest. The plant must be operated to protect customers; therefore, management believes past and future costs of gas processing are recoverable in rates. Management expects to resolve this dispute in 2004.

Depreciation expense decreased 3% in the first quarter of 2004 compared with the first quarter of 2003 and 2% in the 12 months ended March 31, 2004, compared with the 2003 period. Retirements of plant have offset the depreciation impact of plant additions.

Consolidated Results After Operating Income

Interest and other income

Lower balances of cash and cash equivalents resulted in lower interest and other income in the first quarter of 2004 compared with the first quarter of 2003. The 12 months ended March 31, 2003, includes gains from selling non-core properties of $39.7 million pretax in the fourth quarter of 2002.

Earnings from unconsolidated affiliates

Rendezvous Gas Services’ income increased in the first quarter of 2004 due to higher throughput. Gas Management is a 50% owner in Rendezvous, which provides gas-gathering services for the Pinedale/Jonah producing area of western Wyoming. Questar Pipeline’s 50% share of the TransColorado partnership is included in the trailing 12 months ended March 31, 2003. TransColorado contributed $6.8 million of pretax earnings before a fourth quarter 2002 sale.

Debt expense

Lower debt balances and interest rates resulted in lower debt expense in 2004. In 2003 Questar Gas replaced higher-cost fixed-rate debt with lower-cost fixed-rate debt.

Income taxes

The effective combined federal and state income tax rate was 37.7% in both 2004 and 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

	3 Months Ended
	March 31,
	2004	2003
	(in thousands)
Net income	$  76,133	$  64,622
Noncash adjustments to net income	73,677	61,968
Changes in operating assets and liabilities	21,807	3,620
Net cash provided from operating activities	$171,617	$130,210

Net cash provided from operating activities increased 32% in 2004 compared with 2003 due to increased income and noncash adjustments to income. However higher realized prices for gas and oil in 2004 resulted in an increase in receivables, inventories and hedging collateral deposits.

Investing Activities

A comparison of capital expenditures for the first quarter of 2004 and 2003 plus an estimate for calendar year 2004 is presented below.

			Forecast
	Actual		12 Months
	3 Months Ended		Ended
	March 31,		Dec. 31,
	2004	2003	2004
	(in thousands)
Market Resources	$ 34,130	$ 21,764	$270,900
Questar Pipeline	3,572	3,465	51,000
Questar Gas	15,642	9,926	82,800
Corporate and other operations	538	426	10,000
	$ 53,882	$ 35,581	$414,700

Financing Activities

Net cash flow provided from operating activities was more than sufficient to fund capital expenditures and pay dividends in the first quarter of 2004. The excess cash flow was used to repay debt. As a result total debt was 43% of total capital at March 31, 2004. Questar Gas borrowed $110 million and redeemed $41 million of long-term debt in the first quarter of 2003 and an additional $64 million in April 2003.

Short-term debt amounted to $34 million of commercial paper with an average rate of 1.07% at March 31, 2004. The Company's lines-of-credit capacity as of April 1, 2004, was $200 million.

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’ earnings, rate of return and cash flow targets and protect earnings from downward movements in commodity prices. The volume of hedged production and the mix of derivative instruments are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by Market Resources’ Board of Directors. 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 and 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 March 31, 2004 approximately 49.8 bcf of forecast 2004 gas production is hedged at an average price of $4.00 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 March 31, 2004, was $11.6 million.

A summary of Market Resources’ hedging positions for equity production as of March 31, 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.   

	Rocky				Rocky
Time periods	Mountains	Midcontinent		Total	Mountains	Midcontinent	Total
	Gas (in bcf)				Average price per Mcf, net to the well
Second quarter of 2004	10.7	6.0	16.7		$3.70	$4.53	$4.00
Second half of 2004	21.0	12.1	33.1		3.69	4.53	4.00
April – Dec. of 2004	31.7	18.1	49.8		3.69	4.53	4.00
First half of 2005	14.8	7.7	22.5		$3.93	$4.44	$4.11
Second half of 2005	15.0	7.9	22.9		3.93	4.44	4.11
12 months of 2005	29.8	15.6	45.4		3.93	4.44	4.11
First half of 2006	2.1	1.6	3.7		$4.09	$4.81	$4.41
Second half of 2006	2.1	1.7	3.8		4.09	4.81	4.41
12 months of 2006	4.2	3.3	7.5		4.09	4.81	4.41

	Oil (in Mbbl)			Average price per bbl, net to the well
Second quarter of 2004	334	91	425	$30.96	$31.22	$31.01
Second half of 2004	552	184	736	30.91	31.22	30.99
April – Dec. of 2004	886	275	1,161	30.93	31.22	31.00

First half of 2005	91	90	181	$29.80	$30.20	$30.00
Second half of 2005	92	92	184	29.80	30.20	30.00
12 months of 2005	183	182	365	29.80	30.20	30.00

Market Resources held gas-price hedging contracts covering the price exposure for about 148.2 MMdth of gas and 1.5 MMbbl of oil as of March 31, 2004. A year earlier Market Resources’ hedging contracts covered 107.2 MMdth of natural gas and 800,000 bbl of oil. Market Resources does not hedge the price of NGL.

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

	(in thousands)
Net fair value of gas- and oil-hedging contracts outstanding at December 31, 2003	($49,098)
Contracts realized or otherwise settled	24,160
Increase in gas and oil prices on futures markets	(48,452)
Contracts added since December 31, 2003	(268)
Net fair value of gas- and oil-hedging contracts outstanding at March 31, 2004	($73,658)

A vintaging of the net fair value of gas-hedging contracts as of March 31, 2004, is shown below. About 70% of all contracts will settle and be reclassified from other comprehensive income in the next 12 months.

	(in thousands)
Contracts maturing by March 31, 2005	($51,559)
Contracts maturing between March 31, 2005 and March 31, 2006	(23,249)
Contracts maturing between March 31, 2006 and March 31, 2007	1,458
Contracts maturing after March 31, 2007	(308)
Net fair value of gas- and oil-hedging contracts at March 31, 2004	($73,658)

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.

	At March 31,
	2004	2003
	(in millions)
Mark-to-market valuation – asset (liability)	($73.7)	($44.5)
Value if market prices of gas and oil decline by 10%	(16.7)	(12.2)
Value if market prices of gas and oil increase by 10%	(131.4)	(77.0)

Gas and Oil Reserve Estimates

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 substantially. 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 our 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. Further 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.

Presence of Wildlife and Potential Endangered Species Listing Could Limit Access to Public Lands

Various wildlife species occupy portions of Market Resources’ leasehold at Pinedale and the company’s acreage in other areas. Current federal regulations restrict activities during certain times of the year on portions of Market Resources leasehold 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 the company’s leasehold in places or during periods when the particular species is found to be present.

Interest-Rate Risk Management

As of March 31, 2004 Questar had $950.2 million of fixed-rate long-term debt and no amounts of variable-rate long-term debt.

Western Segment of Questar Southern Trails Pipeline

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 is actively seeking customers willing to enter into long-term gas transportation contracts necessary to place the pipeline into service. The company is also considering selling this pipeline, and has received non-binding indications of interest from several interested parties. Questar Pipeline's investment in the western segment is approximately $52 million.

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) and 15d-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, the Company’s 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 or in other factors that could significantly affect such controls.

Part II

OTHER INFORMATION

Item 5  Other Information.

a.

Effective February 10, 2004, Phillips S. Baker, Jr. was appointed to serve as a director of Questar Corporation ("Questar" or the "Company") for the remainder of a term that expires in May of 2005.  Mr. Baker, age 44, is the President and Chief Executive Officer of Hecla Mining Company, a position he has held since May of 2003.  He joined Hecla as Vice President and Chief Financial Officer in May 2001 and also served as Chief Operating Officer from November 2001 to May 2003.  Mr. Baker also serves as a director of Hecla.  Prior to joining Hecla, he served as Vice President and Chief Financial Officer of Battle Mountain Gold Company from March 1998 to January 2001.

b.

Martin H. Craven, age 52, was appointed to serve as Questar's Treasurer effective March 1, 2004, succeeding S. E. Parks who continues to serve the Company as Senior Vice President and Chief Financial Officer.  Mr. Craven joined the Company in 1990 and previously held several positions in the treasury department, most recently as Assistant Treasurer.  He also serves as the Company's Director, Investor Relations.

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 Report on Form 8-K:  Current Report dated February 10, 2004, filing a copy of the Company's earnings release for the period ended December 31, 2003.

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)

May 7, 2004__________

/s/Keith O. Rattie_____________________

Date

Keith O. Rattie

Chairman, President and Chief Executive

Officer

May 7, 2004__________

/s/S. E. Parks_________________________

Date

S. E. Parks

Senior Vice President and Chief Financial

Officer

Exhibit List

Exhibit No.

Exhibit

12.	Ratio of earnings to fixed charges.
31.1.	Certification signed by Keith O. Rattie, Questar Corporation's Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2.	Certification signed by S. E. Parks, Questar Corporation'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 Corporation's Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 12
Questar Corporation and Subsidiaries
Ratio of Earnings to Fixed Charges
	12 Months Ended
	March 31,
	2004	2003
	(dollars in thousands)
Earnings
Income before income taxes and
cumulative effect of accounting change	$291,232	$296,282
Less company's share of earnings of
equity investees	(5,282)	(12,156)
Plus distributions equity investees	4,497	14,454
Less minority interest in loss (gain)	125	(408)
Plus debt expense	69,336	80,001
Plus allowance for borrowed funds used
during construction	174	815
Plus interest portion of rental expense	2,569	2,649
	$362,651	$381,637
Fixed Charges
Debt expense	$69,336	$80,001
Plus allowance for borrowed funds used
during construction	174	815
Plus interest portion of rental expense	2,569	2,649
	$72,079	$83,465
Ratio of Earnings to Fixed Charges	5.03	4.57

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

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.

May 7, 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.

May 7, 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 March 31, 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

May 7, 2004___________

/s/Keith O. Rattie___________________

Date

Keith O. Rattie

Chairman, President and Chief Executive

Officer

May 7, 2004____________

/s/S. E. Parks_____________________

Date

S. E. Parks

Senior Vice President and Chief

Financial Officer