QUESTAR CORP - 10-Q Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003.

		OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE TRANSITION PERIOD FROM TO .

Commission File Number 1-8796

QUESTAR CORPORATION

(Exact name of registrant as specified in its charter)

State of Utah		87-0407509
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification Number)

P.O. Box 45433 180 East 100 South Salt Lake City, Utah		84145-0433
(Address of principal executive offices)		(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 ý

No o

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

Yes ý

No o

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 October 31, 2003
Common Stock, without par value with attached Common Stock Purchase Rights		83,043,728 Shares

Questar Corporation and Subsidiaries

Form 10-Q for the Quarterly Period Ended September 30, 2003

TABLE OF CONTENTS

PART I	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Income Statements	3

	Condensed Consolidated Balance Sheets	4

	Condensed Consolidated Statements of Cash Flows	5

	Notes Accompanying Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	21

Item 4.	Controls and Procedures	26


PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	27

Item 6.	Exhibits and Reports on Form 8-K	28

	Signatures	29

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

QUESTAR CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	3 Months Ended September 30,						9 Months Ended September 30,						12 Months Ended September 30,
	2003			2002			2003			2002			2003			2002
	(In Thousands, Except Per Share Amounts)
REVENUES
Questar Market Resources	$	179,980		$	108,877		$	549,153		$	357,580		$	714,049		$	489,906
Questar Regulated Services
Natural gas distribution	71,054			59,347			396,162			402,309			587,688			612,541
Natural gas transmission	17,777			18,015			55,417			44,855			76,837			58,409
Other	1,328			770			3,686			2,553			5,293			3,691
Corporate and other operations	3,364			3,661			9,558			10,520			12,959			19,702
TOTAL REVENUES	273,503			190,670			1,013,976			817,817			1,396,826			1,184,249

OPERATING EXPENSES
Cost of natural gas and other products sold	79,423			17,328			350,723			243,414			503,051			405,858
Operating and maintenance	66,307			67,368			208,355			206,523			286,149			287,700
Depreciation, depletion and amortization	47,536			46,953			141,172			136,723			189,401			179,906
Distribution rate-refund obligation	1,462						23,462						23,462
Exploration	961			1,102			3,174			4,983			4,277			7,952
Abandonment and impairment of gas, oil and other properties	1,087			1,411			2,062			2,466			10,779			3,553
Production and other taxes	17,882			10,329			52,413			33,933			62,672			41,878
TOTAL OPERATING EXPENSES	214,658			144,491			781,361			628,042			1,079,791			926,847

OPERATING INCOME	58,845			46,179			232,615			189,775			317,035			257,402

Interest and other income	1,818			1,329			6,617			17,894			45,390			31,689
Earnings from unconsolidated affiliates	1,329			6,328			3,687			10,090			5,374			10,974
Minority interest	38			4			168			301			368			572
Debt expense	(17,306		)	(20,488		)	(53,734		)	(60,886		)	(73,969		)	(78,706		)

INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECTS	44,724			33,352			189,353			157,174			294,198			221,931
Income taxes	16,033			9,995			70,188			54,294			107,020			76,470
INCOME BEFORE CUMULATIVE EFFECTS	28,691			23,357			119,165			102,880			187,178			145,461
Cumulative effect of accounting change for asset retirement obligations, net of income taxes of $3,331							(5,580		)				(5,580		)
Cumulative effect of accounting change for goodwill, net of $2,010 attributed to minority interest										(15,297		)				(15,297		)
NET INCOME	$	28,691		$	23,357		$	113,585		$	87,583		$	181,598		$	130,164

BASIC EARNINGS PER COMMON SHARE
Income before cumulative effects	$	0.35		$	0.28		$	1.45		$	1.26		$	2.28		$	1.78
Cumulative effects							(0.07		)	(0.19		)	(0.07		)	(0.19		)
Net income	$	0.35		$	0.28		$	1.38		$	1.07		$	2.21		$	1.59

DILUTED EARNINGS PER COMMON SHARE
Income before cumulative effects	$	0.34		$	0.28		$	1.42		$	1.25		$	2.24		$	1.77
Cumulative effects							(0.07		)	(0.19		)	(0.07		)	(0.19		)

NET INCOME	$	0.34		$	0.28		$	1.35		$	1.06		$	2.17		$	1.58

Weighted average common shares outstanding
Used in basic calculation	82,896			81,842			82,600			81,728			82,318			81,631
Used in diluted calculation	84,398			82,398			84,043			82,487			83,622			82,320

Dividends per common share	$	0.205		$	0.18		$	0.575		$	0.54		$	0.76		$	0.72

See notes accompanying the consolidated financial statements

QUESTAR CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,						December 31,
	2003			2002			2002
	(Unaudited)
	(In Thousands)
ASSETS
Current assets
Cash and cash equivalents	$	5,744		$	5,222		$	21,641
Accounts receivable, net	118,336			85,711			154,498
Unbilled gas accounts receivable	10,424			9,305			39,788
Fair value of hedging contracts	4,895			8,828			3,617
Inventories, at lower of average cost or market
Gas and oil storage	45,023			32,526			29,666
Materials and supplies	11,924			10,612			10,679
Purchased-gas adjustments	5,669
Prepaid expenses and other	10,812			7,650			15,008
Deferred income taxes - current				845			5,047
Total current assets	212,827			160,699			279,944
Property, plant and equipment	4,391,137			4,248,504			4,211,551
Less accumulated depreciation, depletion and amortization	1,707,353			1,593,793			1,593,753
Net property, plant and equipment	2,683,784			2,654,711			2,617,798
Investment in unconsolidated affiliates	32,340			151,586			23,617
Goodwill	71,133			72,702			71,133
Intangible pension asset	16,911						16,911
Regulatory and other assets	61,181			56,724			58,447
	$	3,078,176		$	3,096,422		$	3,067,850
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term loans	$	39,500		$	221,505		$	49,000
Accounts payable and accrued expenses	199,348			170,048			213,936
Fair value of hedging contracts	33,423			18,895			24,278
Purchased-gas adjustments				2,223			13,282
Deferred income taxes - current	2,154
Current portion of long-term debt	11			18,831			10
Total current liabilities	274,436			431,502			300,506

Long-term debt, less current portion	1,005,187			1,178,440			1,145,180
Deferred income taxes and investment tax credits	424,797			330,266			382,282
Other long-term liabilities	55,816			46,559			51,574
Asset retirement obligation	54,630
Pension liability	34,387			2,328			39,522
Minority interest	7,919			10,005			10,025
Common shareholders’ equity
Common stock	318,289			294,427			298,718
Retained earnings	934,777			815,848			868,702
Other comprehensive loss	(32,062		)	(12,953		)	(28,659		)
Total common shareholders’ equity	1,221,004			1,097,322			1,138,761
	$	3,078,176		$	3,096,422		$	3,067,850

See notes accompanying the consolidated financial statements

QUESTAR CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	9 Months Ended September 30,
	2003			2002
	(In Thousands )
OPERATING ACTIVITIES
Net income	$	113,585		$	87,583
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation, depletion and amortization	148,180			143,875
Deferred income taxes and investment tax credits	55,060			20,944
Abandonment and impairment of gas and oil properties	2,062			2,466
Income from unconsolidated affiliates, net of cash distributions	1,727			4,490
Amortization of restricted shares	872
Net (gain) loss from selling properties and securities	260			(6,517		)
Impairment of securities available for sale				530
Minority interest	(168		)	(302		)
Cumulative effect of accounting changes, net of taxes	5,580			15,297
	327,158			268,366
Changes in operating assets and liabilities	23,595			96,556
NET CASH PROVIDED FROM OPERATING ACTIVITIES	350,753			364,922

INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(183,118		)	(245,192		)
Other investments	(11,110		)	(11,148		)
Total capital expenditures	(194,228		)	(256,340		)
Proceeds from the disposition of assets	7,428			27,335
NET CASH USED IN INVESTING ACTIVITIES	(186,800		)	(229,005		)

FINANCING ACTIVITIES
Issuance of common stock	20,123			7,291
Common stock repurchased	(2,862		)	(1,254		)
Issuance of long-term debt	110,000			325,000
Repayment of long-term debt	(249,992		)	(127,039		)
Change in short-term loans	(9,500		)	(308,741		)
Change in cash held in escrow account				6,838
Payment of dividends	(47,510		)	(44,143		)
Other	(109		)	53
NET CASH USED IN FINANCING ACTIVITIES	(179,850		)	(141,995		)
Change in cash and cash equivalents	(15,897		)	(6,078		)
Beginning cash and cash equivalents	21,641			11,300
Ending cash and cash equivalents	$	5,744		$	5,222

See notes accompanying the consolidated financial statements

QUESTAR CORPORATION AND SUBSIDIARIES

NOTES ACCOMPANYING CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2003

(Unaudited)

Note 1 - Basis of Presentation of Interim Financial Statements

The accompanying consolidated financial statements of Questar Corporation (Questar or the Company), with the exception of the condensed consolidated balance sheet at December 31, 2002, have not been audited by independent public accountants. The interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair presentation of the results of operations for the interim periods presented. All such adjustments are of a normal recurring nature. Questar Market Resources, Inc. (Market Resources) manages commodity-price risk through the use of natural-gas and oil-price hedging instruments. Due to the seasonal nature of the gas distribution business, the results of operations for the three-, nine- and twelve-month periods ended September 30 are not necessarily indicative of the results that may be expected for the year ending December 31, 2003. 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. For further information please refer to the financial statements and notes thereto included in the Annual Report on Form 10-K for the year ended December 31, 2002, that was filed by Questar.

Note 2 – Utah Supreme Court Order in Questar Gas Carbon Dioxide Case

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 of 1999. The stipulation permitted Questar Gas to collect $5 million per year in rates to recover a portion of the costs incurred to reduce the level of carbon dioxide in gas volumes delivered to customers. 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 $22 million liability for a potential refund to gas distribution customers. The liability reflects revenue received for processing costs from June of 1999 through June of 2003. This charge reduced Questar’s consolidated net income by $13.6 million or $.16 per diluted share. For safety reasons, the Company has decided to continue to operate the plant. The cost for the second half of 2003 will be approximately $1.6 million after tax or $.02 per diluted share, before interest. Thereafter, annual costs will be approximately $3.2 million after tax or $.04 per diluted share, before interest. Recording the liability did not have a material impact on the credit, cash or liquidity of Questar or Questar Gas. Questar Gas has requested ongoing rate coverage for CO₂ costs in its recent gas cost pass-through. Until the issue is decided by the PSCU, Questar Gas will record a liability for potential refund of the ongoing CO₂ processing costs being collected in rates.

The processing plant was constructed and is operated by Questar Transportation Services, a subsidiary of Questar Pipeline Company (Questar Pipeline). Questar Gas determined that contracting with Questar Transportation Services was the lowest cost alternative. The net book value of the plant was approximately $17.4 million as of September 30, 2003.

Questar Gas believes that it acted prudently and in the best interests of its customers to incur the processing costs and that the PSCU should now decide the prudence issue. It has requested the PSCU proceed with the original case and find Questar Gas’s actions were prudent. The Committee is arguing that the PSCU is precluded from proceeding with the case and has requested the PSCU immediately order refunds. Questar Gas and the Committee filed briefs on September 25, responsive briefs on October 23 and reply briefs on November 5. The PSCU has not issued any further decisions and timing for resolution of the CO2 case is uncertain since any PSCU order may be subject to appeals.

Note 3 -New Accounting Standard

On January 1, 2003, Questar adopted Statement of Financial Accounting Standards 143 (SFAS 143) “Accounting for Asset Retirement Obligations” and recorded a $5.6 million after tax charge ($.07 per diluted share) for the cumulative effect of this accounting change. SFAS 143 addresses the financial accounting and reporting of the fair value of legal obligations associated with the retirement of tangible long-lived assets. The new standard requires the Company to estimate a fair value of abandonment costs and to capitalize and depreciate those costs over the life of the related assets. The asset retirement obligation is adjusted to its present value each period through an accretion process using a credit-adjusted risk-free interest rate. Both the accretion expense associated with the liability and the depreciation associated with the capitalized abandonment costs are non-cash expenses. The adoption of SFAS 143 caused Questar to change the accounting method for plugging and abandonment costs associated with gas and oil wells and certain other properties. SFAS 143 was applied retroactively to prior years to determine the cumulative effect through December 31, 2002. Questar Gas recorded a regulatory asset at January 1, 2003, amounting to $6.6 million representing a retroactive charge for the abandonment costs associated with gas wells operated on its behalf by Wexpro. The regulatory asset will be reduced as the gas wells are plugged and abandoned.

The accretion expense in the first nine months of 2003 amounted to $1,519,000. If SFAS 143 had been in effect for the first nine months of 2002, accretion expense would have been $1,234,000.

Changes in asset retirement obligation

	(In Thousands)

Balance at January 1, 2003	$	51,486
Accretion	2,516
Additions	1,279
Properties sold	(579		)
Retirements	(72		)
Balance at September 30, 2003	$	54,630

Note 4 - Goodwill and Other

Intangible Assets

The following table shows pro forma net income calculated by excluding goodwill transactions. Amortization of goodwill was not deductible for income tax purposes.

	9 Months Ended September 30,				12 Months Ended September 30,
	2003		2002		2003		2002
	(In Thousands)

Net income	$	113,585	$	87,583	$	181,598	$	130,164
Goodwill amortization deducted in prior periods							555
Cumulative effect of change in accounting for goodwill, net of $2,010 attributed to minority interest			15,297				15,297
Pro forma net income	$	113,585	$	102,880	$	181,598	$	146,016

Basic earnings per share
Income before cumulative effects	$	1.38	$	1.07	$	2.21	$	1.59
Goodwill amortization							0.01
Cumulative effect			0.19				0.19
Pro forma net income	$	1.38	$	1.26	$	2.21	$	1.79

Diluted earnings per share
Income before cumulative effects	$	1.35	$	1.06	$	2.17	$	1.58
Cumulative effect			0.19				0.19
Pro forma net income	$	1.35	$	1.25	$	2.17	$	1.77
Weighted average common shares outstanding
Used in basic calculation	82,600		81,728		82,318		81,631
Used in diluted calculation	84,043		82,487		83,622		82,320

Goodwill in each line of business at September 30, 2003, was unchanged from the balances at December 31, 2002.

Note 5 - 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 shares exceed basic shares because diluted shares include the potential increase in the number of outstanding shares that could result from exercising stock options.

In the first nine months of 2003, the number of issued common shares increased 931,000 as a result of several plans. These plans include the Long-Term Stock Incentive Plan, the Dividend Reinvestment and Stock Purchase Plan, and the Employee Investment Plan.

	3 Months Ended September 30,		9 Months Ended September 30,		12 Months Ended September 30,
	2003	2002	2003	2002	2003	2002
	(In Thousands)
Average basic common shares outstanding	82,896	81,842	82,600	81,728	82,318	81,631
Potential number of shares issuable under stock option plans	1,502	556	1,443	759	1,304	689
Average diluted common shares outstanding	84,398	82,398	84,043	82,487	83,622	82,320

Note 6 - Stock-based Compensation

The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board (APB) Opinion 25, “Accounting for Stock Issued to Employees” and related interpretations. Under this method, no compensation expense is recorded by the Company for stock options granted because the exercise price of those options is equal to the market price of the Company’s common stock on the date of grant. A table showing pro forma income as if the options were expensed follows:

	3 Months Ended September 30						9 Months Ended September 30						12 Months Ended September 30
	2003			2002			2003			2002			2003			2002
	(In Thousands)

Net income, as reported	$	28,691		$	23,357		$	113,585		$	87,583		$	181,598		$	130,164

Stock-based compensation expense determined under a fair value based method	(1,363		)	(1,392		)	(4,089		)	(4,176		)	(5,481		)	(6,260		)
Pro forma net income	$	27,328		$	21,965		$	109,496		$	83,407		$	176,117		$	123,904

Earnings per share

Basic, as reported	$	0.35		$	0.28		$	1.38		$	1.07		$	2.21		$	1.59
Basic, pro forma	0.33			0.27			1.33			1.02			2.14			1.52
Diluted, as reported	0.34			0.28			1.35			1.06			2.17			1.58
Diluted, pro forma	0.32			0.27			1.30			1.01			2.11			1.51

Note 7 - Operations by Line of Business

	3 Months Ended September 30						9 Months Ended September 30						12 Months Ended September 30
	2003			2002			2003			2002			2003			2002
	(In Thousands)

REVENUES FROM UNAFFILIATED CUSTOMERS
Questar Market Resources	$	179,980		$	108,877		$	549,153		$	357,580		$	714,049		$	489,906
Questar Regulated Services
Natural gas distribution	71,054			59,347			396,162			402,309			587,688			612,541
Natural gas transmission	17,777			18,015			55,417			44,855			76,837			58,409
Other	1,328			770			3,686			2,553			5,293			3,691
Total Regulated Services	90,159			78,132			455,265			449,717			669,818			674,641
Corporate and other operations	3,364			3,661			9,558			10,520			12,959			19,702
	$	273,503		$	190,670		$	1,013,976		$	817,817		$	1,396,826		$	1,184,249

REVENUES FROM AFFILIATED COMPANIES
Questar Market Resources	$	29,282		$	24,807		$	85,688		$	81,717		$	110,618		$	106,861
Questar Regulated Services
Natural gas distribution	444			145			1,901			1,243			2,334			1,592
Natural gas transmission	20,104			18,317			59,750			58,198			78,152			77,126
Other	579			422			1,493			1,236			1,944			1,546
Corporate and other operations	6,863			7,669			21,198			22,803			28,852			29,366
	$	57,272		$	51,360		$	170,030		$	165,197		$	221,900		$	216,491

OPERATING INCOME (LOSS)
Questar Market Resources	$	48,560		$	30,565		$	156,329		$	97,226		$	189,547		$	126,259
Questar Regulated Services
Natural gas distribution	(9,820		)	(3,908		)	16,804			39,209			47,949			63,173
Natural gas transmission	18,346			17,176			53,921			47,884			72,222			63,214
Other	52			(144		)	410			(333		)	402			(457		)

Total Regulated Services	8,578			13,124			71,135			86,760			120,573			125,930
Corporate and other operations	1,707			2,490			5,151			5,789			6,915			5,213
OPERATING INCOME	$	58,845		$	46,179		$	232,615		$	189,775		$	317,035		$	257,402

NET INCOME (LOSS)
Questar Market Resources	$	27,352		$	16,000		$	89,177		$	56,419		$	130,687		$	75,523
Questar Regulated Services
Natural gas distribution	(8,259		)	(4,667		)	1,287			15,990			17,696			28,498
Natural gas transmission	7,857			8,842			23,252			24,128			31,732			32,168
Other	36			(211		)	273			99			334			1,855
Total Regulated Services	(366		)	3,964			24,812			40,217			49,762			62,521
Corporate and other operations	1,705			3,393			5,176			6,244			6,729			7,417
Income before cumulative effects of accounting changes	28,691			23,357			119,165			102,880			187,178			145,461
Cumulative effect							(5,580		)	(15,297		)	(5,580		)	(15,297		)
NET INCOME	$	28,691		$	23,357		$	113,585		$	87,583		$	181,598		$	130,164

Cumulative effect of accounting changes by lines of business are shown below. The accounting change for asset retirement obligations was effective January 1, 2003, and for goodwill was effective January 1, 2002.

	Asset Retirement Obligation		Goodwill
	(In Thousands)

Questar Market Resources	$	5,113
Questar Regulated Services
Natural gas distribution	334
Natural gas transmission	133
Total Regulated Services	467
Corporate and other operations			$	15,297
Total	$	5,580	$	15,297

Note 8 – Financing

On January 24, 2003, Questar Gas issued $40 million of ten-year notes with an effective interest rate of 5.02%. The proceeds were used to redeem $41 million of debt with a coupon rate of 8.4%. Questar Gas paid a $1.7 million call premium. This issue completed a Form S-3 shelf registration for issuance of up to $100 million of medium-term notes filed by Questar Gas in the third quarter of 2001.

On February 27, 2003, Questar Gas filed a shelf registration statement for the issuance of up to $70 million of medium-term notes. In March 2003, Questar Gas sold $70 million of 15-year notes with a coupon rate of 5.31%. On April 24, 2003, proceeds from the offering were used to redeem $64 million of higher-cost debt issued in 1992 and 1993 with a weighted-average interest rate of 8.11%. Questar Gas paid a call premium of $2.6 million.

Questar has a shelf registration statement to issue up to $400 million of common equity or debt convertible into common stock. The filing registered both the $200 million convertible debt that could be issued and the subsequent common stock that would be issued in a convertible debt offering. Currently, there are no plans to issue securities under this shelf registration.

Note 9 - Investment in Unconsolidated Affiliates

Questar, indirectly through subsidiaries, has interests in businesses accounted for on the equity basis. These entities are engaged primarily in the gathering and/or processing of natural gas. The entities do not have debt obligations with third-party lenders. Questar uses the equity method to account for investments in affiliates in which it does not have control. The principal affiliates and Market Resources ownership percentage as of September 30, 2003 were: Rendezvous Gas Services LLC, a limited liability corporation, (50%) and Canyon Creek Compression Co., a general partnership, (15%). Gathering and processing results for the 2002 period presented included an affiliate’s 50% interest in Blacks Fork Processing. Since the fourth quarter of 2002, Blacks Fork Processing is 100% owned by an affiliate of Market Resources. TransColorado Pipeline, which was sold in the fourth quarter of 2002, and Overthrust Pipeline, of which subsidiaries of Questar Pipeline own 100% since the fourth quarter of 2002, comprised the transportation businesses.

Summarized operating results of the businesses are listed below.

	9 Months Ended September 30,
	2003		2002
	(In Thousands )

Gas gathering and processing
Revenues	$	11,860	$	16,996
Operating income	7,190		5,438
Income before income taxes	7,217		5,492
Transportation
Revenues	$	—	$	24,992
Operating income	—		14,732
Income before income taxes	—		14,791

Note 10 - Comprehensive Income

Comprehensive income is the sum of net income as reported in the Consolidated Statements of Income and other comprehensive income transactions reported in Shareholders’ Equity. Other comprehensive income transactions include changes in the market value of securities available for sale, gas and oil hedging derivatives and foreign currency translation adjustments. These transactions are not the culmination of the earnings process, but result from periodically adjusting historical balances to market value. Income or loss is realized when the securities available for sale are sold or the gas or oil underlying the hedging contracts are sold.

	3 Months Ended September 30,					9 Months Ended September 30,
	2003		2002			2003			2002
			(In Thousands)

Net income	$	28,691	$	23,357		$	113,585		$	87,583
Other comprehensive income
Unrealized income (loss) on hedging transactions	34,513		(11,965		)	(5,415		)	(57,824		)
Unrealized gain (loss) on securities available for sale			314						(5,242		)
Foreign currency translation adjustment			(2,126		)				113
Other comprehensive income (loss) before income taxes	34,513		(13,777		)	(5,415		)	(62,953		)
Income taxes on other comprehensive income (loss)	12,917		(5,763		)	(2,012		)	(23,924		)
Net other comprehensive income (loss)	21,596		(8,014		)	(3,403		)	(39,029		)
Total comprehensive income	$	50,287	$	15,343		$	110,182		$	48,554

Note 11 – Reclassification

Certain reclassifications were made to the 2002 financial statements to conform with the 2003 presentation.

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

September 30, 2003

(Unaudited)

Results of Operations

Questar Market Resources

Questar Market Resources and subsidiaries (Market Resources) acquire and develop gas and oil properties, develop cost-of-service reserves for an affiliated company, Questar Gas, provide gas-gathering and processing services, market equity and third-party gas and oil, provide risk-management services, and own and operate an underground gas-storage reservoir. Primary objectives of gas- and oil-marketing operations are to support Market Resources’ earnings targets and to protect Market Resources’ earnings from adverse commodity-price changes. Market Resources does not enter into gas- and oil-hedging contracts for speculative purposes. Following is a summary of Market Resources’ financial results and operating information:

	3 Months Ended September 30,				9 Months Ended September 30,					12 Months Ended September 30,
	2003		2002		2003			2002		2003			2002
FINANCIAL RESULTS - (In thousands)
Revenues
From unaffiliated customers	$	179,980	$	108,877	$	549,153		$	357,580	$	714,049		$	489,906
From affiliates	29,282		24,807		85,688			81,717		110,618			106,861
Total revenues	$	209,262	$	133,684	$	634,841		$	439,297	$	824,667		$	596,767
Operating income	$	48,560	$	30,565	$	156,329		$	97,226	$	189,547		$	126,259
Income before cumulative effect	$	27,352	$	16,000	$	89,177		$	56,419	$	130,687		$	75,523
Cumulative effect of accounting change					(5,113		)			(5,113		)

Net income	$	27,352	$	16,000	$	84,064		$	56,419	$	125,574		$	75,523

OPERATING STATISTICS
Nonregulated production volumes
Natural gas (in MMcf)	19,524		19,594		57,585			59,457		77,802			79,949
Oil and natural gas liquids (in Mbbl)	586		717		1,726			2,200		2,290			2,968
Total production (Bcfe)	23.0		23.9		67.9			72.7		91.5			97.8
Average daily production (MMcfe)	250		260		249			266		251			268

Average selling price, net to the well
Average realized selling price (including hedges)
Natural gas (per Mcf)	$	3.56	$	2.49	$	3.58		$	2.49	$	3.39		$	2.53
Oil and natural gas liquids (per bbl)	$	22.69	$	21.03	$	23.28		$	20.15	$	22.80		$	19.09

Average selling price (without hedges)
Natural gas (per Mcf)	$	4.18	$	1.90	$	4.24		$	1.97	$	3.86		$	2.00
Oil and natural gas liquids (per bbl)	$	27.39	$	24.86	$	28.38		$	22.12	$	27.82		$	21.07

Wexpro investment base at September 30, net of depreciation and deferred income taxes (in millions)	$	161.2	$	165.8
Energy marketing volumes (in MDthe)	19,788		17,004		57,999			59,580		82,235			83,061

Natural gas gathering volumes (in MDth)
For unaffiliated customers	28,807		25,562		85,164			82,408		114,961			106,051
For Questar Gas	8,103		7,881		29,202			29,886		40,001			40,058
For other affiliated customers	10,717		8,828		31,744			25,480		44,400			32,747
Total gathering	47,627		42,271		146,110			137,774		199,362			178,856
Gathering revenue (per Dth)	$	0.20	$	0.15	$	0.20		$	0.15	$	0.19		$	0.15

Third quarter and first nine months comparison of 2003 with 2002

Exploration and Production (E&P)

Market Resources’ net income in the third quarter and nine months ended September 30, 2003 benefited from higher realized prices for natural gas, oil and natural gas liquids. Realized natural gas prices, net to the well, increased 43% in the third quarter and 44% year to date when compared with the same periods of 2002. Higher natural gas prices result from tight supply and growing demand, and increased pipeline capacity out of the Rockies. The May 1, 2003, startup of an expansion of a regional pipeline added transportation capacity of 900,000 Mcf per day out of the supply-rich but transportation-constricted Rockies.

Roughly two-thirds of the Company’s 2003 nonregulated production came from properties located in the Rockies. Rockies basis differential in 2003 averaged more than $2.50 per MMBtu prior to May 1, measured against the Henry Hub benchmark, but has subsequently returned to the historical range of $.40 to $.60 per MMBtu. Market Resources realized a 62% increase in gas prices for Rockies production in the third quarter of 2003 compared with the third quarter of 2002. A year ago lower gas prices caused Market Resources to voluntarily shut-in a total of 3.3 Bcfe of Rockies production. Realized Midcontinent gas prices were 27% higher in the same third quarter comparison.

Market Resources has taken advantage of recent higher energy prices to increase its natural gas price hedge positions. Market Resources has hedged 15.1 Bcf of forecasted fourth quarter 2003 natural gas production at $3.71 per Mcf and 67.6 Bcf of forecasted 2004 natural gas production at $4.02 per Mcf, net to the well. Fees for gathering and processing are deducted from market prices to arrive at net-to-the-well prices.

Approximately 68% of nonregulated gas production in the first nine months of 2003 was hedged or presold at an average price of $3.23 per Mcf, net to the well resulting in a $38.2 million revenue reduction when compared with the prices received from the physical sales transactions. During the same time period, approximately 53% of nonregulated oil production was hedged or presold at an average price of $21.80 per bbl, net to the well, resulting in an $8.8 million reduction in oil revenues. While this has resulted in lower revenues compared with an unhedged position, it has met the Company’s goal of locking in energy prices that enable the Company to meet or exceed income growth and cash flow targets, while reducing volatility. In the first nine months of 2002, hedging activities added $26.9 million of revenues.

Production, measured in natural gas-equivalents, was 4% lower in the quarter-to-quarter comparison and 6% lower in the first nine-month comparison. The decline resulted from the sale of Market Resources’ Canadian E&P operations, some San Juan

E&P properties and other non-core, producing properties in the second half of 2002. Sequentially, the third quarter 2003 gas production exceeded second quarter 2003 gas production by 1.6 Bcf.

The Company expects to replace production capacity that declined as a result of the 2002 sale of producing properties. Increased drilling in Market Resources’ Pinedale Anticline area has yielded increased production. Rockies production increased 14% in the third quarter year-to-year comparison. Following is a table showing production volumes in Bcfe by region:

	3 Months Ended September 30,		9 Months Ended September 30,
	2003	2002	2003	2002
		(In Bcfe)
Region
Rockies	15.0	13.2	44.3	40.7
Midcontinent	8.0	8.3	23.6	24.5
Canada		2.4		7.5
Total	23.0	23.9	67.9	72.7

Market Resources has drilled, or is drilling, 27 new wells in the Pinedale Anticline in 2003. To date, 11 wells have been fully completed and are producing to sales, 11 are in various stages of completion or waiting on completion and 5 are currently drilling. In addition, 5 wells that were drilled and completed in 2002 have been recompleted in 2003 to add behind pipe Lance pay intervals and 1 well (the first winter pad well, Stewart Point #4-33) was drilled to targeted depth in December 2002 and completed in 2003. Five of the 6 wells completed in the deeper Mesaverde intervals in 2002 were produced through the winter to test the productivity of this deeper horizon before being commingled with Lance production. Incremental reserves from the deeper Mesaverde interval are estimated to average 2 Bcfe per well. Based on the encouraging test results, all of Market Resources’ 2003 wells will be drilled to the Mesaverde formation. The 2003 wells that have reached targeted depth have encountered 50 to 120 feet of net pay sand in the Mesaverde and flowed at rates of 1 to 9 million cubic feet equivalent per day (MMcfe/d).

Market Resources forecasts that 24 of the 27 wells drilled in 2003 will be completed and turned to sales by year-end. As of October 15, 2003, gross production capability from 63 Market Resources-operated Pinedale wells was 170 MMcfe/d. By mid-November 2003, Market Resources expects to have 76 operated producing wells with anticipated gross production capacity of over 200 MMcfe/d, up 60% from year end 2002.

Market Resources is drilling directional wells from common pads to reduce surface disturbance and maximize utilization of production facilities. The estimated cost of a directional Lance and Mesaverde well completed in 12 intervals is $4.5 million. Average gross estimated ultimate recovery from 40 acre spaced Lance/Mesaverde wells has averaged 8 Bcfe per well. Market Resources has approximately a 62% average working interest in 14,800 gross acres in the Mesa Area of the Pinedale Anticline and anticipates that there are between 225 and 250 well locations on its acreage based on 40 acre spacing.

Ongoing review of production data from individual Wasatch Formation gas wells drilled during the past several years by Questar E&P and wells drilled by a previous owner Shenandoah Energy (SEI) indicates that well performance in some areas is falling significantly below what was expected at the time of acquisition. Current average reserves for all Wasatch Formation wells completed to date is approximately 0.8 Bcfe, compared to predicted reserves of 1.0 to 1.2 Bcfe at the time of the acquisition of SEI. Factors causing reduced well performance include high variability of the size, quality and thickness of individual reservoirs and difficulties in optimizing the gathering system to handle the highly variable flowing wellhead pressures that exist between different age wells. Market Resources continues to evaluate and adjust its reserve base to reflect performance-related revisions.

Lifting costs per Mcfe were higher in the 2003 periods presented due to a higher production tax component driven up by higher selling prices. Lease operating expenses were lower in the 2003 periods after the 2002 sale of higher-cost Canadian properties. General and administrative costs were higher in the 2003 periods due primarily to increased employee benefit costs and property insurance costs. Depreciation, depletion and amortization rates were higher in the 2003 periods due to the higher costs of developing Market Resources’ Uinta properties. A third quarter and first nine months comparison of operating costs for nonregulated production on an Mcfe basis is shown in the table below.

	3 Months Ended September 30,				9 Months Ended September 30,
	2003		2002		2003		2002
			(Per Mcfe)

Lease operating expense	$	0.47	$	0.56	$	0.48	$	0.55
Production taxes	0.34		0.15		0.32		0.16
Lifting cost	0.81		0.71		0.80		0.71

Depreciation, depletion and amortization	0.98		0.93		0.94		0.89
General and administrative expense	0.29		0.27		0.28		0.27
Allocated interest expense	0.23		0.29		0.24		0.28
Total	$	2.31	$	2.20	$	2.26	$	2.15

Wexpro Earnings

Wexpro’s net income was $100,000 lower in the third quarter of 2003 compared with the third quarter of 2002 due to the timing of well completions, which are expected to occur in the fourth quarter of 2003. Wexpro earns a return on its net investment in commercial wells drilled to develop reserves owned by Questar Gas. The return is calculated according to the terms of the Wexpro settlement agreement and has averaged 19% to 20% after-tax. Wexpro’s earnings for the first nine months of 2003 were $500,000 higher than the corresponding 2002 period due to higher realized prices for oil, capitalized interest associated with construction, and lower debt expense. Wexpro’s first quarter 2003 results included a $600,000 after tax charge for the cumulative effect of an accounting change.

Gas Gathering; Gas and Oil Marketing

Net income from gas gathering operations in 2003 benefited from higher fees and increased volumes gathered. In addition, Market Resources’ 50% interest in the earnings in Rendezvous Gas Services increased from $530,000 in the third quarter of 2002 to $1.2 million in the third quarter of 2003. Rendezvous provides gathering and processing services for the Pinedale and Jonah producing areas. The marketing margin, which represents revenues less the costs to purchase gas and oil and transport gas, was up $206,000 in the first nine months of 2003 compared with 2002, but was down $805,000 in the third quarter of 2003 compared with 2002 due to unused transportation capacity.

Comparison of 12 months ended September 30, 2003 and 2002

Higher realized prices for gas, oil and natural gas liquids were responsible for a 38% increase in revenues when comparing the 12 months ended September 30, 2003, with the corresponding period of 2002. Production, measured in natural gas equivalents was 6% lower in the 2003 period due to sales of non-core producing properties. A majority of the asset sales took place in the fourth quarter of 2002.

Lifting costs per Mcfe increased by 7% in the 12-month comparison due to higher production taxes that more than offset a reduction in lease operating expenses. General and administrative costs were higher in 2003 due to higher employee benefit costs and property insurance costs. A comparison of the information for the 12 months ended September 30, 2003 and 2002 on an Mcfe basis is shown in the table below.

	12 Months Ended September 30,
	2003		2002
	(Per Mcfe)

Lease operating expense	$	0.49		$	0.58
Production taxes	0.30			0.16
Lifting cost	$	0.79		$	0.74
Depreciation, depletion and amortization	$	0.94		$	0.90
General and administrative expense	0.29			0.26
Allocated interest expense	0.24			0.26
Total	$	2.26		$	2.16

Questar Regulated Services

Questar Gas and Questar Pipeline conduct the regulated services of natural gas distribution, interstate transmission and storage and unregulated processing and gathering.

Natural Gas Distribution

Questar Gas conducts natural gas distribution operations. Following is a summary of financial results and operating information.

	3 Months Ended September 30,						9 Months Ended September 30,						12 Months Ended September 30,
	2003			2002			2003			2002			2003			2002
FINANCIAL RESULTS - (In thousands)
Revenues
From unaffiliated customers	$	71,054		$	59,347		$	396,162		$	402,309		$	587,688		$	612,541
From affiliates	444			145			1,901			1,243			2,334			1,592
Total revenues	71,498			59,492			398,063			403,552			590,022			614,133
Cost of natural gas sold	43,838			26,743			242,954			251,934			361,314			396,664
Margin	$	27,660		$	32,749		$	155,109		$	151,618		$	228,708		$	217,469
Operating income (loss)	$	(9,820	)	$	(3,908	)	$	16,804		$	39,209		$	47,949		$	63,173
Income (loss) before cumulative effect	$	(8,259	)	$	(4,667	)	$	1,287		$	15,990		$	17,696		$	28,498
Cumulative effect of accounting change							(334		)				(334		)
Net income (loss)	$	(8,259	)	$	(4,667	)	$	953		$	15,990		$	17,362		$	28,498

OPERATING STATISTICS
Natural gas volumes (in MDth)
Residential and commercial sales	6,719			6,954			55,186			61,099			84,883			90,338
Industrial sales	1,710			1,882			7,138			7,678			10,189			10,588
Transportation for industrial customers	9,873			12,774			28,846			34,465			40,840			46,383
Total industrial	11,583			14,656			35,984			42,143			51,029			56,971
Total deliveries	18,302			21,610			91,170			103,242			135,912			147,309

Natural gas revenue (per Dth)
Residential and commercial	$	8.46		$	6.75		$	6.31		$	5.74		$	6.12		$	5.98
Industrial sales	5.30			3.42			4.52			4.34			4.27			4.50
Transportation for industrial customers	0.19			0.16			0.19			0.16			0.18			0.15
Heating degree days colder (warmer) than normal	(9		)%	(30		)%	(9		)%	11		%	(5		)%	7		%
Average temperature-adjusted usage per customer (Dth)	9.1			9.8			78.4			77.0			118.8			118.0
Number of customers at September 30,
Residential and commercial	754,307			733,986
Industrial	1,236			1,281
Total	755,543			735,267

Third Quarter Earnings

Questar Gas’s seasonal third quarter loss increased from $4.7 million in 2002 to $8.3 million in 2003. The 2002 quarter benefited from a $2.3 million after-tax settlement related to gas processing costs. However, this amount was later part of a potential liability charge in the second quarter of 2003. In addition, Questar Gas accrued an additional $900,000 after tax charge in the third quarter for gas processing costs. Questar Gas’s rate structure is more seasonal as a result of a December 2002 general rate case as explained below.

Revenues less cost of natural gas sold (margin)

Questar Gas’s margin was 16% lower in the third quarter of 2003 when compared with the third quarter of 2002 primarily due to a one-time recovery of gas costs and CIAC collected in 2002. The 2002 quarter benefited from an August 2002 one-time recovery of $3.8 million of gas costs, which had been previously denied. The PSCU’s order allowing the recovery was later reversed by a Utah Supreme Court ruling dated August 1, 2003. CIAC amounted to $1.5 million in the third quarter of 2002.

Higher general rates, more customers and higher usage per customer resulted in an increase in Questar Gas’s margin for the first nine months of 2003. These factors more than offset the effect of the 2002 $3.8 million recovery of gas costs, CIAC received in 2002 and elimination of a new premise fee in the general rate case. The number of customers increased 20,276 or 2.8% in the year to year comparison. Temperature adjusted usage per customer grew by 2% in the first nine months of 2003 compared with the same period in 2002. The weather-normalization adjustment (WNA) mitigates the financial effect of temperatures that are either colder or warmer than normal. Generally, under the WNA customers pay for the non-gas costs reflected in rates based on normal temperatures.

The margin for the 12-months ended September 30, 2003, was higher when compared with the corresponding period of 2002 due to several factors in addition to those discussed above. Beginning in 2002 the PSCU authorized Questar Gas to recover the gas cost portion of bad debt expense in pass through gas costs. Also, gas volumes delivered to industrial customers were lower in the 2003 periods presented due to decreased gas usage for generation of electricity and in manufacturing processes.

Expenses

Operating and maintenance expenses were higher in the 2003 periods presented when compared to the same periods in 2002 due primarily to higher labor-related costs.Labor-related expenses have increased primarily because of higher costs of pension and benefit programs and less construction-related capitalization of labor costs. Higher depreciation expense in the first nine months of 2003 reflects increased investment in computer equipment and software, which are depreciated over a shorter life than service lines and meters.

Rate Refund Obligation

The Utah Supreme Court issued an order reversing decisions made by the PSCU in August of 2000 and August of 2002. The PSCU originally permitted Questar Gas to collect $5 million per year to recover costs incurred to process certain gas volumes delivered to customers. In August 2002, the PSCU allowed an additional $3.8 million of recovery from a previous period. As a result of the order, Questar Gas recorded a $22 million liability in the second quarter of 2003. The liability reflects a potential refund of gas processing costs collected in rates from June of 1999 through June of 2003. In the third quarter of 2003, Questar Gas increased the liability by a $1.5 million charge including interest.

Natural Gas Transmission

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

	3 Months Ended September 30				9 Months Ended September 30					12 Months Ended September 30
	2003		2002		2003			2002		2003			2002
FINANCIAL RESULTS - (In thousands)
Revenues
From unaffiliated customers	$	17,777	$	18,015	$	55,417		$	44,855	$	76,837		$	58,409
From affiliates	20,104		18,317		59,750			58,198		78,152			77,126
Total revenues	$	37,881	$	36,332	$	115,167		$	103,053	$	154,989		$	135,535
Operating income	$	18,346	$	17,176	$	53,921		$	47,884	$	72,222		$	63,214
Income before cumulative effect	$	7,857	$	8,842	$	23,252		$	24,128	$	31,732		$	32,168
Cumulative effect of accounting change					(133		)			(133		)
Net income	$	7,857	$	8,842	$	23,119		$	24,128	$	31,599		$	32,168

OPERATING STATISTICS
Natural gas transportation volumes (in MDth)
For unaffiliated customers	68,557		65,453		195,953			173,699		267,373			225,787
For Questar Gas	13,412		14,704		79,132			91,971		98,853			123,495
For other affiliated customers	6,786		1,228		15,989			2,525		19,508			5,431
Total transportation	88,755		81,385		291,074			268,195		385,734			354,713

Transportation revenue (per Dth)	$	0.25	$	0.30	$	0.25		$	0.25	$	0.26		$	0.25

Third Quarter Earnings

Questar Pipeline’s third quarter earnings were $7.9 million in 2003 compared with $8.8 million in 2002. Lower construction activity in 2003 resulted in higher operating and maintenance costs due to reduced construction-related capitalized costs. Also, the TransColorado pipeline contributed to 2002 third quarter income before its sale in the fourth quarter.

Revenues

Revenues were higher in the 2003 periods compared with the 2002 periods due primarily to increased transportation capacity and contracted services. Total firm daily demand was 1,524,000 Dth in the first nine months of 2003 compared with 1,421,000 Dth in the first nine months of 2002. Higher volumes were primarily the result of the startup of the eastern segment of the Questar Southern Trails pipeline mid-year 2002. The eastern segment of Southern Trails has a capacity of 80,000 Dth daily, which is fully-contracted through 2006. Beginning in May 2003, Questar Pipeline expanded its transportation service to the Kern River pipeline and deliveries subsequently increased by an average of 155,000 Dth per day. Gas transported on Overthrust pipeline accounted for about 55% of the increase.

Revenues in the 2003 periods also benefited from higher prices received for natural gas liquids removed from the transmission line, revenues from nonjurisdictional gas gathering and park and loan storage fees.

Expenses

Lower construction activity resulted in lower capitalization of costs and caused increased operating and maintenance expenses in a comparison of the year to date periods of 2003 and 2002. In addition, employee benefit costs, insurance and pipeline inspection costs are higher in the 2003 periods. The higher level of investment in pipeline projects of past years resulted in higher depreciation expenses and property taxes in the 2003 periods. Capitalized financing costs related to construction were significantly lower in 2003.

Consolidated Operating Results After Operating Income

Gains from property sales and the settlement of a lawsuit benefited interest and other income in the 2002 periods. The sale of a Canadian E&P subsidiary, San Juan E&P properties and other E&P properties accounted for pretax gains of $38.0 million in the 12 months ended September 30, 2003. Market Resources settled a lawsuit in the second quarter of 2002 resulting in a pretax gain of $4.5 million.

Rendezvous Gas Services’ income increased in the 2003 periods presented due to higher volumes and rates. A Market Resources subsidiary is a 50% owner in Rendezvous, which provides gathering and processing services for the Pinedale and Jonah producing areas of western Wyoming. The Company’s share of earnings from TransColorado, Overthrust and Blacks Fork are included in the 2002 periods.

Lower debt balances and lower variable interest rates resulted in lower debt expenses in the 2003 periods when compared with the 2002 periods. In 2002, the Company applied the proceeds of approximately $250 million from asset sales to repay debt. In addition, Questar Gas replaced higher cost debt with lower cost debt in 2003.

The effective income tax rate for the first nine months was 37.1% in 2003 and 34.5% in 2002. An income tax credit associated with non-conventional fuels expired December 31, 2002. The Company recognized $4.6 million of non-conventional fuel tax credits in the first nine months of 2002, of which $3.3 million was attributable to Market Resources.

Cumulative Effect of Changes in Accounting Methods

On January 1, 2003, the Company adopted a new accounting rule, SFAS 143, “Accounting for Asset Retirement Obligations” and recorded a cumulative effect that reduced net income by $5.6 million or $.07 per diluted common share. Accretion expense associated with SFAS 143 amounted to $1.5 million in the first nine months of 2003. A year earlier, the Company adopted the provisions of SFAS 142, “Goodwill and Other Intangible Assets” that resulted in impairment of the goodwill acquired by Consonus. The Company wrote off $17.3 million of goodwill, of which, $15.3 million or $.19 per diluted common share was attributed to Questar InfoComm’s share and reported as a cumulative effect of a change in accounting for goodwill. The remaining $2.0 million was attributed to minority shareholders.

Liquidity and Capital Resources

Operating Activities

In the first nine months, net cash provided from operating activities amounted to $350.8 million, which was $14.2 million less than was provided during the same period of 2002. Increased net income, primarily from higher gas and oil prices, was offset by lower cash flows from accounts receivable and purchased-gas adjustments due to timing differences. Higher energy prices resulted in an increase in the value of gas placed in storage.

Investing Activities

A comparison of capital expenditures for the first nine months of 2003 and 2002 plus a forecast for calendar year 2003 is presented below. Accelerated development of Market Resources’ interest in the Pinedale Anticline of Wyoming and related operations is a significant portion of 2003 expenditures. Forecasted capital expenditures for Corporate and Other Operations include $11 million and $25 million that have not been committed to specific projects in 2003 and 2004, respectively.

	Actual 9 Months Ended September 30,				Forecast 12 Months Ended December 31,
	2003		2002		2003		2004
			(In Thousands)

Questar Market Resources	$	126,942	$	130,380	$	244,600	$	245,900
Questar Regulated Services
Natural gas distribution	46,253		42,489		82,300		82,800
Natural gas transmission	18,333		81,197		40,600		51,000
Other	811		1,206		3,500		5,400
Total Questar Regulated Services	65,397		124,892		126,400		139,200
Corporate and Other Operations	1,889		1,068		14,500		29,600
	$	194,228	$	256,340	$	385,500	$	414,700

Financing Activities

Net cash flow provided from operating activities exceeded the sum of net capital expenditures and dividends by $116.4 million. The excess cash flow plus the proceeds from issuing $110 million of long-term fixed rate debt were used to repay debt. Market Resources paid down its revolving debt by $145 million. Questar Gas refinanced $105 million of debt in the first half of 2003. Total debt as a percentage of capitalization was 46% at September 30, 2003, compared with 56% a year earlier. The Company used proceeds from asset sales in 2002 to reduce debt balances.

The Company’s lines-of-credit capacity as of October 1, 2003, was $210 million. Short-term debt amounted to $39.5 million of commercial paper at September 30, 2003. A year earlier, short-term debt was comprised of $121.5 million of commercial paper and $100 million of borrowings from banks.

Item 3. Quantitative and Qualitative disclosures About Market Risk

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

Commodity-Price Risk Management

Market Resources bears a majority of 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. The primary objectives of natural gas- and oil-price hedging are to support Market Resources’ earnings targets, and to protect earnings from downward movements in commodity prices. The volume of production hedged and the mix of derivative instruments employed are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by Market Resources’ Board of Directors. Market Resources intends to hedge up to 100% of proved-developed production when the market provides the opportunity to do so at attractive prices. Proved-developed production represents production from existing wells. Market Resources does not enter into derivative arrangements for speculative purposes and does not hedge undeveloped reserves. Hedges are matched to equity gas and oil production, thus qualifying as cash flow hedges under the accounting provisions of SFAS 133 as amended and interpreted. Gas hedges are structured as fixed-price swaps into regional pipelines locking in basis and hedge effectiveness.

Hedges are more heavily weighted to the Rockies to reduce basis risk and to protect returns on capital in the Uinta Basin. Approximately 90% of Rockies fourth quarter 2003 proved-developed production is hedged at an average price of $3.53 per Mcf, net to the well. In addition, Market Resources may curtail production if prices drop below levels necessary for profitability.

Market Resources has entered 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. The Company maintains lines of credit to cover potential collateral calls. There was no such collateral required at September 30, 2003.

A summary of Market Resources’ gas— and oil-price hedging positions for equity gas and oil production as of October 14, 2003, is below. Prices are net to the well. Currently, all hedges are fixed-price swaps with creditworthy counterparties, which allow the Company to achieve a known price for a specific volume of gas delivered into a regional pipeline, i.e., incorporating a known basis. The swap price is then reduced by gathering and processing costs to determine the net-to-the-well price.

Time periods	Rocky Mountains	Midcontinent	Total	Rocky Mountains		Midcontinent		Total
	Gas (in Bcf)			Average price per Mcf, net to the well
Fourth quarter of 2003	10.8	4.3	15.1	$	3.53	$	4.14	$	3.71

First half of 2004	22.5	12.0	34.5	3.78		4.53		4.04
Second half of 2004	21.0	12.1	33.1	3.69		4.53		3.99
12 months of 2004	43.5	24.1	67.6	3.74		4.53		4.02

First half of 2005	5.4	3.5	8.9	3.67		4.37		3.94
Second half of 2005	5.6	3.5	9.1	3.67		4.37		3.94
12 months of 2005	11.0	7.0	18.0	3.67		4.37		3.94

	Oil (in MBbl)			Average price per Bbl, net to the well
Fourth quarter of 2003	230	46	276	$	21.68	$	22.38	$	21.80

Market Resources held gas- and oil-price hedging contracts covering the price exposure for about 121.9 million dth of gas and 276,000 bbl of oil as of September 30, 2003. The contracts existed for both equity gas and oil and marketing transactions. A year earlier Market Resources hedging contracts covered 83.6 million dth of natural gas and 1.6 million bbl of oil. Market Resources does not hedge the price of natural gas liquids.

A summary of the activity for the fair value of hedging contracts for the nine months ended September 30, 2003, is shown below. The calculation is comprised of the valuation of financial and physical contracts.

	(In Thousands)

Net fair value of gas- and oil-hedging contracts outstanding at Dec. 31, 2002	$	(20,661	)
Contracts realized or otherwise settled	10,676
Increase in gas and oil prices on futures markets	(18,181		)
New contracts since Dec. 31, 2002	(362		)
Net fair value of gas - and-oil-hedging contracts outstanding at September 30, 2003	$	(28,528	)

A vintaging of the net fair value of gas-and oil-hedging contracts as of September 30, 2003, is shown below. About 81% of those contracts will settle and be reclassified from other comprehensive income in the next 12 months.

	(In Thousands)

Contracts maturing by September 30, 2004	$	(23,031	)
Contracts maturing between September 30, 2004 and September 30, 2005	(5,467		)
Contracts maturing between September 30, 2005 and September 30, 2006	(10		)
Contracts maturing between September 30, 2006 and September 30, 2008	(20		)
Net fair value of gas-and oil-hedging contracts outstanding at September 30, 2003	$	(28,528	)

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

	As of September 30,
	2003			2002
	(In Millions)

Mark-to-market valuation - asset (liability)	$	(28.5	)	$	(10.1	)
Value if market prices of gas and oil decline by 10%	6.0			(8.7		)
Value if market prices of gas and oil increase by 10%	(63.1		)	(11.4		)

Interest-Rate Risk Management

As of September 30, 2003, Questar had $55 million of variable-rate long-term debt and $950.2 million of fixed-rate long-term debt. In addition, the Company has $39.5 million of variable-rate short-term debt at September 30, 2003. Generally, the imbedded cost of fixed-rate debt exceed rates currently available in the market. The book value of variable-rate long-term debt approximates fair value.

OTHER INFORMATION

Purchased-Gas Cost Filings

Effective July 1, 2003, the PSCU approved a $146.4 million pass-on increase in annual gas costs for Utah customers. Subsequently, gas prices have fallen. Effective October 1, 2003, the PSCU approved a $43.4 million pass-on decrease in annual gas cost. The Public Service Commission of Wyoming (PSCW) granted Questar Gas permission to pass on a $6.8 million increase in gas costs to Wyoming customers also effective July 1, 2003. Also, the PSCW approved a $1.7 million pass-on decrease effective October 1, 2003 due to falling gas costs. Pass-on rate increases or decreases result in equal adjustments of revenues and gas costs without affecting the earnings of Questar Gas.

Western Segment of Questar Southern Trails Pipeline Company

Questar Pipeline has thus far been unsuccessful in its efforts to secure long-term contracts required to place the western segment of the Southern Trails pipeline into service. The western segment extends from the California-Arizona border to Long Beach, California. Questar Southern Trails Pipeline Company, a subsidiary of Questar Pipeline, is actively seeking customers willing to enter into long-term gas transportation contracts necessary to place the western segment into service. Questar Pipeline is also considering selling this pipeline, and has received non-binding offers from several interested parties. A decision to place in-service or sell the pipeline is expected by the end of 2003 or early 2004. Questar Southern Trails Pipeline’s investment in the western segment is approximately $53 million.

Federal Energy Regulatory Commission (FERC) - Notice of Proposed Rulemaking (NOPR) on Affiliated Relations

The FERC has proposed rules requiring pipelines to comply with certain “nondiscriminatory” standards when dealing with affiliated energy companies including state regulated local distribution companies. At the current time, local distribution companies (LDCs) such as Questar Gas that do not engage in unregulated gas sales are exempt from the FERC’s marketing affiliate regulations. Questar Regulated Services believes that the current exemption should be continued, but the FERC has not yet made a decision on whether affiliate rules should be expanded to include gas LDCs such as Questar Gas. A FERC decision to extend energy affiliate rules to include LDCs could result in higher costs for Questar Pipeline and Questar Gas. Questar Pipeline and Questar Gas realize significant cost savings by sharing the cost of administrative, engineering, gas control, technical, accounting, legal and regulatory services.

FERC - NOPR on Quarterly Financial Reporting

The FERC issued a NOPR on Quarterly Financial Reporting and Revision to the Annual Reports. The NOPR, among other issues, requires a new quarterly filing of financial statements matching the deadlines imposed by the SEC and including a discussion and analysis of earnings for the first time. The FERC has not previously required quarterly statements. The added burden of preparing quarterly reports for the FERC and SEC simultaneously will cause an increase in operating costs.

Recent Accounting Developments

In April 2003, the Financial Accounting Standards Board (FASB) issued SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133. SFAS 149 clarifies (1) under what circumstances a contract with an initial net investment meets the characteristics of a derivative, (2) when a derivative contains a financing component that should be reflected as a financing transaction on the balance sheet and the statement of cash flows and (3) the definition of the term underlying in SFAS 133 to conform to language used in FASB Interpretation 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In addition, SFAS 149 also incorporates certain Derivative Implementation Group Implementation Issues. The provisions of SFAS 149 are effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The guidance is applied to hedging relationships on a prospective basis. Questar does not believe the adoption of SFAS 149 will impact the accounting for its derivative contracts.

The Securities and Exchange Commission has requested that the FASB review the applicability of certain provisions of SFAS 141, “Business Combinations,” and SFAS 142, “Goodwill and Other Intangible Assets,” to companies in the exploration and production business. The issue is whether the provisions of SFAS 141 and SFAS 142 require companies to classify costs associated with mineral rights, including both proved and unproved lease acquisitions costs, as intangible assets on the balance sheet, apart from other capitalized oil and gas property costs. As of September 30, 2003, Market Resources’ proved and unproved leaseholds had a net book value of $401 million.

In January 2003, FASB Interpretation 46 (FIN 46) was issued to address perceived weaknesses in accounting for entities commonly known as special-purpose or off-balance-sheet entities, but the guidance applies to a larger population of entities. FIN 46 provides guidance for identifying the party with a controlling financial interest resulting from arrangements or financial interests rather than from voting interests. FIN 46 defines the term “variable interest entity” (or “VIE”) and is based on the premise that if a business enterprise has a controlling financial interest in a VIE, the assets, liabilities, and results of the activities of the VIE should be included in the consolidated financial statements of the business enterprise. Based upon our initial interpretation of FIN 46, Questar does not believe that this guidance will have a material effect on our financial statements.

FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” within the meaning of Section 27(A) of the Securities Act of 1933, as amended, and Section 21(E) of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” “forecast,” or “continue” or the negative thereof or variations thereon or similar terminology. Although these statements are made in good faith and are reasonable representations of the Company’s expected performance at the time, actual results may vary from management’s stated expectations and projections due to a variety of factors.

Important assumptions and other significant factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements include:

Changes in general economic conditions;

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

Changes in rate-regulatory policies;

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

Creditworthiness of counterparties to hedging contracts;

Rate of inflation and interest rates;

Assumptions used in business combinations;

Weather and other natural phenomena;

The effect of environmental regulation;

Changes in customers’ credit ratings, including energy merchants;

Competition from other forms of energy, other pipelines and storage facilities;

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

Adverse repercussion from terrorist attacks or acts of war;

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

Lower credit ratings for Questar and/or its subsidiaries.

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, 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 or in other factors that could significantly affect such controls.

Part II
OTHER INFORMATION

Item 1. Legal Proceedings.

a. Questar Gas Company (“Questar Gas”), a subsidiary of Questar Corporation (“Questar” or “the Company”) has filed initial and responsive briefs with the Public Service Commission of Utah (“PSCU”) to comply with a scheduling order set by the PSCU following receipt of a decision issued by the Supreme Court of Utah. See the Company’s Quarterly Report on Form 10-Q for the period ending June 30, 2003, Part II, Item 1. Legal Proceedings, for a description of this decision in which the court found that the PSCU did not comply with regulatory procedures when approving a stipulation in Questar Gas’s 1999 general rate case permitting the recovery of specified carbon dioxide removal costs.

In its briefs, Questar Gas contends that the PSCU should proceed with deliberations in the 1999 general rate case to consider the prudence of incurring costs for the removal of carbon dioxide from gas volumes to enhance the heating value of such volumes. This processing provides customers with a transitional period to have their appliances adjusted, if necessary, to burn gas volumes with a lower heating value. The Committee of Consumer Services, the Utah state agency that filed and won the appeal, argues that the PSCU should order Questar Gas to refund the costs it has collected in rates for such processing activities. Two additional parties to the original stipulation have asked the PSCU to answer whether it made a prudence finding in the 1999 case and, if not, to proceed with making such a determination.

Questar Gas filed a reply brief with the PSCU on November 5, 2003. Oral arguments will be presented to the PSCU on December 11, 2003. Pending the outcome of the regulatory proceedings and possible legal appeals, Questar Gas is continuing to collect the processing costs as part of its gas costs, but has recorded a liability equal to the total amount of such costs recovered in rates plus interest.

b. Questar Exploration and Production Company (“QEP”), a subsidiary of the Company, is a named defendant in a lawsuit that was recently filed in Oklahoma state district court. Kaiser-Francis Oil Co. v. Anadarko Petroleum Corp. (Okla. Dist. Ct. 2003). The case stems from a major class action lawsuit (Bridenstine v. Kaiser Francis Oil Co.) involving allegations of improper royalty payments for wells connected to an intrastate pipeline system in western Oklahoma. QEP and Anadarko Petroleum Corporation (as the successor to Union Pacific Resources Co.) settled the lawsuit in December of 2000 and were dismissed as parties. Kaiser-Francis, another named defendant, chose not to settle and had a jury verdict in excess of $59 million (including interest and reflecting a credit for the settlement) entered against it.

In the new lawsuit, Kaiser-Francis asserts claims of express and implied indemnity against its former co-defendants and for specified damages assessed against it and for its legal defense costs. QEP intends to file an answer in the case denying that it is responsible for any portion of the damages assessed to Kaiser-Francis and raising other issues and defenses.

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, the Company filed the following Current Reports on Form 8-K: Current Report dated July 31, 2003, filing a copy of Questar’s earnings release for periods ended June 30, 2003; Current Report dated August 1, 2003, disclosing the Supreme Court of Utah’s adverse decision in Questar Gas’s 1999 general rate case; and Current Report dated September 16, 2003, providing updated earnings guidance.

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 12, 2003			/s/Keith O. Rattie
Date			Keith O. Rattie Chairman, President and Chief Executive Officer


November 12, 2003			/s/S. E. Parks
Date			S. E. Parks Senior Vice President, Treasurer, 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’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.