UNITED STATES

10-Q 1 qmr10q_3q2004.htm 10Q UNITED STATES

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 SEPTEMBER 30, 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 0-30321

QUESTAR MARKET RESOURCES, INC.

(Exact name of registrant as specified in its charter)

State of Utah (State or other jurisdiction of incorporation or organization)		87-0287750 (IRS Employer Identification Number)

P.O. Box 45601 180 East 100 South Salt Lake City, Utah (Address of principal executive offices)		84145-0601 (Zip code)

(801) 324-2600
(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 [ ]		No [X]

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, 2004
Common Stock, $1.00 par value		4,309,427 shares

Registrant meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is filing this Form 10-Q with the reduced disclosure format.

Questar Market Resources, Inc.

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

TABLE OF CONTENTS

Page #

PART I.

FINANCIAL INFORMATION

Item 1.

Financial Statements.

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

ended September 30, 2004 and 2003.

Condensed Consolidated Balance Sheets at September 30, 2004

and December 31, 2003.

Condensed Consolidated Statements of Cash Flows for the nine-months

ended September 30, 2004 and 2003.

Notes Accompanying Consolidated Financial Statements.

Item 2.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations.

Item 3.

Quantitative and Qualitative Disclosures about Market Risk.

Item 4.

Controls and Procedures.

PART II.

OTHER INFORMATION

Item 1.

Legal Proceedings.

Item 6.

Exhibits and Reports on Form 8-K

Signatures

Glossary of Commonly Used Terms

bbl

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

basis

The difference between a reference or benchmark commodity price and the corresponding sales 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 drilled and found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

dth

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

exploratory well

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

fixed-price swaps

Fixed-price swaps are derivative instruments used to exchange variable prices for future deliveries of gas and oil into fixed prices.

futures contract

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

gross

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

hedging

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

Mbbl

One thousand barrels.

Mcf

One thousand cubic feet.

Mcfe

One thousand cubic feet of natural gas equivalents.

Mdth

One thousand decatherms.

Mdthe

One thousand decatherm equivalents.

MMbbl

One million barrels.

MMBtu

One million British Thermal Units.

MMcf

One million cubic feet.

MMcfe

One million cubic feet of natural gas equivalents.

MMdth

One million decatherms.

natural gas liquids

Liquid hydrocarbons that are extracted and separated from the natural gas stream.

(“NGL”)

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.

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 Market Resources, Inc. (“Market Resources” or the “Company”) expected performance at the time, actual results may vary from management’s stated expectations and projections due to a variety of factors.

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

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

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

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

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

PART I FINANCIAL INFORMATION
Item 1. Financial Statements.
QUESTAR MARKET RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2004	2003	2004		2003
	(in thousands)

REVENUES	$284,597	$209,262	$831,458	$634,841

OPERATING EXPENSES
Cost of natural gas and other products sold	128,876	83,709	350,893	249,319
Operating and maintenance	34,577	30,400	106,807	94,938
Depreciation, depletion and amortization	34,238	30,533	105,271	88,597
Exploration	1,346	961	3,699	3,174
Abandonment and impairment of gas, oil and other properties	2,848	1,087	9,541	2,062
Production and other taxes	17,180	13,568	52,332	38,526
Wexpro Agreement - oil income sharing	1,101	444	3,249	1,896

TOTAL OPERATING EXPENSES	220,166	160,702	631,792	478,512

OPERATING INCOME	64,431	48,560	199,666	156,329

Interest and other income	459	681	1,472	2,939
Income from unconsolidated affiliates	1,021	1,329	3,595	3,687
Minority interest		38	(270)	129
Debt expense	(6,728)	(7,145)	(20,602)	(21,613)

INCOME BEFORE INCOME TAXES
AND CUMULATIVE EFFECT	59,183	43,463	183,861	141,471

Income taxes	21,972	16,111	68,232	52,294

INCOME BEFORE CUMULATIVE EFFECT	37,211	27,352	115,629	89,177

Cumulative effect of accounting change
for asset retirement obligations, net of
income taxes of $3,049				(5,113)

NET INCOME	$ 37,211	$ 27,352	$115,629	$ 84,064

See notes accompanying consolidated financial statements

QUESTAR MARKET RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,	December 31,
	2004	2003
	(Unaudited)
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents		$ 3,716
Notes receivable from Questar	$ 15,700	6,900
Accounts receivable, net	165,756	148,870
Hedging collateral deposits	63,910	9,100
Fair value of hedging contracts	2,398	3,861
Inventories, at lower of average cost or market -
Gas and oil storage	20,630	17,179
Materials and supplies	8,454	3,769
Prepaid expenses and other	12,539	9,394
Total current assets	289,387	202,789
Property, plant and equipment	2,312,169	2,149,171
Less accumulated depreciation, depletion and amortization	907,063	816,845
Net property, plant and equipment	1,405,106	1,332,326
Investment in unconsolidated affiliates	35,347	36,393
Goodwill	61,423	61,423
Other assets	14,627	13,030
	$1,805,890	$1,645,961

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Checks in excess of cash balances	$ 9,702
Notes payable to Questar	47,400	$ 36,500
Accounts payable and accrued expenses	213,225	156,979
Fair value of hedging contracts	167,699	52,959
Current portion of long-term debt		55,000
Total current liabilities	438,026	301,438
Long-term debt, less current portion	350,000	350,000
Deferred income taxes	241,511	250,546
Asset-retirement obligation	64,263	60,493
Other long-term liabilities	30,379	25,346
Minority interest		7,864
Common shareholder's equity
Common stock	4,309	4,309
Additional paid-in capital	116,027	116,027
Retained earnings	665,227	562,573
Accumulated other comprehensive loss	(103,852)	(32,635)
Total common shareholder's equity	681,711	650,274
	$1,805,890	$1,645,961

See notes accompanying consolidated financial statements

QUESTAR MARKET RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	9 Months Ended
	September 30,
	2004	2003
	(in thousands)
OPERATING ACTIVITIES
Net income	$115,629	$ 84,064
Adjustments to reconcile net income to net cash
provided from operating activities
Depreciation, depletion and amortization	108,666	91,798
Deferred income taxes	33,606	22,729
Abandonment and impairment of gas, oil and related properties	9,541	2,062
Income from unconsolidated affiliates, net of cash distributions	1,046	1,727
Net (gain) loss from asset sales	(91)	117
Cumulative effect of accounting change		5,113
Minority interest and other	218	(129)
Changes in operating assets and liabilities	(27,128)	(7,773)
NET CASH PROVIDED FROM OPERATING ACTIVITIES	241,487	199,708

INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(189,136)	(116,492)
Other investments	(1,000)	(10,450)
Total capital expenditures	(190,136)	(126,942)
Proceeds from disposition of assets	1,361	6,975
NET CASH USED IN INVESTING ACTIVITIES	(188,775)	(119,967)

FINANCING ACTIVITIES
Change in notes receivable from Questar	(8,800)	67,900
Change in notes payable to Questar	10,900	1,100
Long-term debt repaid	(55,000)	(145,000)
Checks in excess of cash balances	9,702
Dividends paid	(12,975)	(12,975)
Other	(255)	(109)
NET CASH USED IN FINANCING ACTIVITIES	(56,428)	(89,084)
Change in cash and cash equivalents	(3,716)	(9,343)
Beginning cash and cash equivalents	3,716	10,404
Ending cash and cash equivalents	$ -	$ 1,061

See notes accompanying consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

NOTES ACCOMPANYING CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2004

(Unaudited)

Note 1 – Basis of Presentation of Interim Consolidated Financial Statements

The accompanying interim consolidated financial statements of Market Resources, with the exception of the condensed consolidated balance sheet at December 31, 2003, have not been audited by independent public accountants. The unaudited consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. The interim consolidated financial statements reflect all normal, recurring adjustments and accruals that are, in the opinion of management, necessary for a fair presentation of the results of operations for the interim periods presented. The preparation of consolidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities. Actual results could differ from estimates. All significant intercompany accounts and transactions were eliminated in consolidation. Certain reclassifications were made to the 2003 financial statements to conform with the 2004 presentation.

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

Note 2 – Recent Accounting Developments

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

In September 2004 the Emerging Issues Task Force (“EITF”) of the FASB issued proposal 04-9, "Accounting for Suspended Well Costs." GAAP currently requires companies to capitalize the costs of drilling exploratory wells pending determination of whether the well has found proved reserves. The capitalized costs become part of wells, equipment, and facilities if the well finds proved reserves. If proved reserves are not found, the costs are expensed, net of salvage value. The EITF seeks to clarify whether there are circumstances that would permit the continued capitalization of exploratory well costs beyond the one-year limit specified in SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” other than when additional exploration wells are necessary to justify major capital expenditures and those wells are underway or firmly planned for the near future. A ruling from the EITF is expected in the fourth quarter of 2004. The Company has not completed an evaluation of the financial effects, if any, of EITF 04-9.

Note 3 – Asset-Retirement Obligations (“ARO”)

On January 1, 2003, Market Resources adopted SFAS 143 “Accounting for Asset Retirement Obligations.” SFAS 143 addresses the financial accounting and reporting of the fair value of legal obligations associated with the retirement of tangible long-lived assets. The fair value of abandonment costs are estimated and depreciated over the life of the related assets. ARO is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. The majority of Market Resources’ ARO relate to the plugging and abandonment of gas and oil properties.

Changes in asset-retirement obligations were as follows.

	2004	2003
	(in thousands)

Balance at January 1,	$60,493	$55,674
Accretion	1,847	2,470
Additions	1,593	1,279
Revisions	695	(579)
Retirements and properties sold	(365)	(72)
Balance at September 30,	$64,263	$58,772

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

Note 4 – Investment in Unconsolidated Affiliates

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

Operating results are listed below.

	9 Months Ended
	September 30,
	2004	2003
	(in thousands)

Revenues	$12,222	$11,860
Operating income	7,309	7,190
Income before income taxes	7,325	7,217

Note 5 - Operations By Line of Business

Market Resources has three primary reportable segments: Questar Exploration and Production (“Questar E&P”), Wexpro Company (“Wexpro”) and the combined activities of Questar Gas Management Company (“Gas Management”) and Questar Energy Trading Company (“Energy Trading”). Lines of business information are presented according to management’s basis for evaluating performance including differences in the nature of products and services.
	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2004	2003	2004	2003
	(in thousands)
REVENUES FROM UNAFFILIATED CUSTOMERS
Questar E&P	$107,823	$ 83,807	$322,890	$250,401
Wexpro	3,969	3,290	12,170	9,948
Gas Management; Energy Trading	143,472	92,883	398,618	288,804
	$255,264	$179,980	$733,678	$549,153

REVENUES FROM AFFILIATED COMPANIES
Wexpro	$ 26,640	$ 24,797	$ 86,054	$ 75,333
Gas Management; Energy Trading	2,693	4,485	11,726	10,355
	$ 29,333	$ 29,282	$ 97,780	$ 85,688

OPERATING INCOME
Questar E&P	$ 44,831	$ 32,529	$136,157	$102,609
Wexpro	13,578	12,732	42,143	39,058
Gas Management; Energy Trading	6,022	3,299	21,366	14,662
	$ 64,431	$ 48,560	$199,666	$156,329
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE
Questar E&P	$ 24,783	$ 17,344	$ 75,406	$ 55,302
Wexpro	8,737	7,791	26,552	24,443
Gas Management; Energy Trading	3,691	2,217	13,671	9,432
	$ 37,211	$ 27,352	$115,629	$ 89,177
NET INCOME
Questar E&P	$ 24,783	$ 17,344	$ 75,406	$ 50,752
Wexpro	8,737	7,791	26,552	23,880
Gas Management; Energy Trading	3,691	2,217	13,671	9,432
	$ 37,211	$ 27,352	$115,629	$ 84,064

Note 6 – Financing

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

Note 7 – Comprehensive Income

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


	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2004	2003	2004	2003
	(in thousands)

Net income	$ 37,211	$ 27,352	$ 115,629	$ 84,064
Other comprehensive income (loss)
Unrealized income (loss) on hedging transactions	(49,269)	34,513	(113,858)	(5,415)
Income taxes	18,440	(12,917)	42,641	2,012
Other comprehensive income (loss)	(30,829)	21,596	(71,217)	(3,403)
Comprehensive income	$ 6,382	$ 48,948	$ 44,412	$ 80,661

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

September 30, 2004.

(Unaudited)

Results of Operations

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

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2004	2003	2004	2003
FINANCIAL RESULTS - (in thousands)
Revenues
From unaffiliated customers	$255,264	$179,980	$733,678	$549,153
From affiliates	29,333	29,282	97,780	85,688
Total revenues	$284,597	$209,262	$831,458	$634,841
Operating income	$ 64,431	$ 48,560	$199,666	$156,329
Income before cumulative effect	$ 37,211	$ 27,352	$115,629	$ 89,177
Cumulative effect of accounting change				(5,113)
Net income	$ 37,211	$ 27,352	$115,629	$ 84,064

OPERATING STATISTICS
Nonregulated production volumes
Natural gas (MMcf)	21,831	19,524	65,546	57,585
Oil and natural gas liquids (Mbbl)	571	586	1,717	1,726
Total production (bcfe)	25.3	23.0	75.8	67.9
Average daily production (MMcfe)	275	250	277	249

Average commodity prices, net to the well
Average realized price (including hedges)
Natural gas (per Mcf)	$4.07	$3.56	$4.10	$3.58
Oil and natural gas liquids (per bbl)	$31.83	$22.69	$30.28	$23.28
Average sales price (excluding hedges)
Natural gas (per Mcf)	$4.92	$4.18	$4.89	$4.24
Oil and natural gas liquids (per bbl)	$40.55	$27.39	$35.89	$28.38
Wexpro investment base at September 30, net of depreciation and deferred income taxes (millions)	$165.0	$161.2
Natural gas gathering volumes (Mdth)
For unaffiliated customers	32,767	28,807	99,225	85,164
For Questar Gas	8,915	8,103	27,821	29,202
For other affiliated customers	12,995	10,717	40,889	31,744
Total gathering	54,677	47,627	167,935	146,110
Gathering revenue (per dth)	$0.22	$0.20	$0.21	$0.20
Natural gas and oil marketing volumes (Mdthe)	26,285	19,788	68,865	57,999

Market Resources Consolidated Results

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

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

Questar E&P Results

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

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

	3 Months Ending		9 Months Ending
	September 30,		September 30,
	2004	2003	2004	2003
	(in bcfe)
Rocky Mountains
Pinedale Anticline	5.1	3.8	16.0	9.2
Uinta Basin	6.4	7.2	18.8	22.7
Rockies Legacy	4.3	4.0	13.5	12.4
Subtotal – Rocky Mountains	15.8	15.0	48.3	44.3
Midcontinent
Tulsa	5.0	3.5	14.7	10.1
Oklahoma City	4.5	4.5	12.8	13.5
Subtotal – Midcontinent	9.5	8.0	27.5	23.6
Total nonregulated production	25.3	23.0	75.8	67.9

At September 30, 2004, Market Resources operated 88 producing wells on the Pinedale Anticline compared to 58 at the end of the year earlier quarter. Current quarter nonregulated production from Pinedale was 5.1 bcfe compared to 4.9 bcfe in the second quarter and 6.1 bcfe in the first quarter of 2004. Production at Pinedale typically declines during the second and third quarters due to the suspension of drilling and completion activities caused by access restrictions from mid-November to early May. (See the discussion of Pinedale Anticline Drilling Activity later in this Item.) Production volumes from the Uinta Basin in eastern Utah decreased 12% in the current quarter compared to the year earlier period and 17% in the first nine months of 2004 versus the year earlier period. Production decline in the Uinta Basin has flattened significantly from a year ago. Current quarter production from Uinta Basin was 6.4 bcfe compared to 6.1 bcfe in the second quarter and 6.3 bcfe in the first quarter of 2004. Production from Rockies legacy properties in the first nine months of 2004 was 13.5 bcfe compared to 12.4 bcfe in 2003, a 9% increase. Legacy properties include all of Questar E&P’s Rocky Mountain producing properties exclusive of Pinedale and the Uinta Basin. Continued good performance from Questar E&P’s Hartshorne coalbed-methane development project in the Arkoma Basin of eastern Oklahoma and ongoing infill-development drilling on the Elm Grove properties in northwest Louisiana drove Midcontinent results. Current quarter Midcontinent production was up 1.5 bcfe, or 18%, versus the third quarter of 2003.

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

	3 Months Ending		9 Months Ending
	September 30,		September 30,
	2004	2003	2004	2003
Natural gas (per Mcf)
Rocky Mountains	$ 3.79	$ 3.18	$ 3.86	$ 3.15
Midcontinent	4.50	4.22	4.50	4.34
Volume weighted average	$ 4.07	$ 3.56	$ 4.10	$ 3.58
Oil and NGL (per bbl)
Rocky Mountains	$ 31.15	$ 21.34	$ 29.48	$ 21.80
Midcontinent	33.50	26.30	32.15	27.13
Volume weighted average	$ 31.83	$ 22.69	$ 30.28	$ 23.28

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

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

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

	3 Months Ending		9 Months Ending
	September 30,		September 30,
	2004	2003	2004	2003
	(per Mcfe)

Lease-operating expense	$0.52	$0.47	$0.51	$0.48
Production taxes	0.44	0.34	0.43	0.33
Lifting costs	0.96	0.81	0.94	0.81
Depreciation, depletion and amortization	1.04	0.99	1.01	0.95
General and administrative expense	0.29	0.29	0.30	0.28
Allocated-interest expense	0.22	0.23	0.21	0.24
Total	$2.51	$2.32	$2.46	$2.28

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

Pinedale Anticline Drilling Activity

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

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

BLM Approval of Pinedale Anticline Year-Round Drilling

On November 9, 2004, the BLM approved Market Resources’ request for a long-term exception to the winter drilling restrictions on its Pinedale acreage in western Wyoming. The BLM’s decision allows Market Resources to operate two drilling rigs on one pad during the winter of 2004/2005. After completion of proposed water- and condensate- gathering systems during the summer of 2005, Market Resources will then be allowed to operate up to six rigs (two rigs per well pad) from three active pads between November 15 and April 30 each year through the winter of 2013/2014. Between May 1 and November 15 of any year in this period Market Resources can drill with as many rigs as is feasible, with appropriate authorization. The BLM approved Market Resources’ April 2004 request for year-round drilling after conducting a detailed Environmental Assessment and considering extensive input received during its public comment process.

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

In addition to reduced surface disturbance and a shortened development drilling period, other benefits of year-round drilling include a substantial reduction in emissions, noise, dust and traffic compared to the current situation in which activities are compressed into the summer months. The water- and condensate- gathering systems will eliminate the need for storage tanks at each location and up to 25,500 tanker-truck trips per year at peak production. 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. And finally, cutting development time will accelerate not just Market Resources revenues but also tax and royalty revenues for the state of Wyoming.

For additional information regarding the BLM’s approval of Market Resources’ request for year-round drilling see the Company’s Current Report on Form 8-K dated November 9, 2004.

Pinedale Anticline 20-Acre Spacing Approved

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

New Pinedale Leases

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

Wexpro

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

Gas Management and Energy Trading

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

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

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

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 $5.1 million.

Liquidity and Capital Resources

Market Resources’ primary source of liquidity has historically been net cash provided by operating activities. This source has been supplemented as needed by accessing credit lines and commercial paper markets and issuing long-term debt securities.

Operating Activities

Net cash provided from operating activities increased 21% in the first nine months of 2004 compared with 2003 due to higher net income.

Investing Activities

Capital expenditures amounted to $190.1 million in the first nine months of 2004, up 50% over the 2003 period due primarily to increased well-drilling activity. Market Resources budgeted capital expenditures are $343.8 million in 2004 and $375.5 million in 2005 primarily focused on development drilling within Questar E&P and Wexpro.

Financing Activities

Net cash flow provided from operating activities was more than sufficient to fund capital expenditures and pay dividends in the first nine months of 2004. The remaining cash flow was used to repay debt. Total debt was 37% of total capital at September 30, 2004. Market Resources expects to finance 2004 capital expenditures with cash flow from operations.

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 NGL, estimation of gas and oil reserves and volatility in interest rates. Energy Trading has long-term contracts for pipeline capacity and is obligated for transportation services with no guarantee that it will be able to recover the full cost of these transportation commitments.

Commodity-Price-Risk Management

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

Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. Natural gas- and oil-price hedging support Market Resources’ rate of return and cash flow targets and protect earnings from downward movements in commodity prices. The volume of hedged production and the mix of derivative instruments are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by the Finance and Audit Committee of the Board of Directors. Market Resources may hedge up to 100% of forecast nonregulated production from proved-developed reserves when prices meet earnings and cash flow objectives. Proved-developed production represents production from existing wells. Market Resources does not enter into derivative arrangements for speculative purposes and does not hedge undeveloped reserves or equity NGL.

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

As of September 30, 2004, approximately 67.9 bcf of forecast full-year 2004 gas production was hedged at an average price of $4.02 per Mcf, net to the well. Hedges are more heavily weighted to the Rockies to reduce basis risk and to protect returns on capital.

Market Resources enters into commodity-price hedging arrangements with several banks and energy-trading firms. Generally the contracts allow some amount of credit before Market Resources is required to deposit collateral for out-of-the-money hedges. In some contracts the amount of credit varies depending on the credit rating assigned to Market Resources’ debt. Market Resources’ current ratings support counterparty credit ranging from $5 million to $20 million. If Market Resources’ credit ratings fall below investment grade (BBB- by Standard & Poor’s or Baa3 by Moody’s), counterparty credit generally falls to zero. Questar maintains lines of credit to cover potential collateral calls. Collateral required at September 30, 2004, was $63.9 million held in interest-bearing accounts. In October 2004, Market Resources requested an increase in the limitation to $200 million and received approval from its bank group. The collateral calls have not had a material impact on creditworthiness, cash flow or liquidity of Questar or Market Resources.

A summary of Market Resources’ hedging positions for equity production as of September 30, 2004, is shown below. Prices are net to the well. Currently all hedges are fixed-price swaps with creditworthy counterparties, which allows Market Resources to achieve a known price for a specific volume of production delivered into a regional sales point, i.e., incorporating a known basis. The swap price is then reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price.

	Rocky						Rocky
Time periods	Mountains	Midcontinent			Total		Mountains		Midcontinent		Total
	Gas (in bcf)						Average price per Mcf, net to the well

Fourth quarter of 2004	10.5	6.1		16.6			$3.69		$4.53		$4.00

First half of 2005	19.8	11.1		30.9			$4.37		$4.96		$4.58
Second half of 2005	20.1	11.2		31.3			4.37		4.96		4.58
12 months of 2005	39.9	22.3		62.2			4.37		4.96		4.58

First half of 2006	10.5	1.7		12.2			$4.77		$4.81		$4.77
Second half of 2006	10.7	1.7		12.4			4.77		4.81		4.77
12 months of 2006	21.2	3.4		24.6			4.77		4.81		4.77

First half of 2007	1.7			1.7			$5.08				$5.08
Second half of 2007	1.7			1.7			5.08				5.08
12 months 2007	3.4			3.4			5.08				5.08

	Oil (in Mbbl)							Average price per bbl, net to the well

Fourth quarter of 2004	276		92			368		$30.91		$31.22		$30.99

First half of 2005	362		181			543		$33.41		$34.70		$33.84
Second half of 2005	368		184			552		33.41		34.70		33.84
12 months of 2005	730		365			1,095		33.41		34.70		33.84

Market Resources held gas-price hedging contracts covering the price exposure for about 148.3 MMdth of gas and 1.5 MMbbl of oil as of September 30, 2004. A year earlier Market Resources’ hedging contracts covered 121.9 MMdth of natural gas and 276,000 bbl of oil. Market Resources does not hedge the price of equity NGL.

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

			(in thousands)

Net fair value of gas- and oil-hedging contracts outstanding at December 31, 2003			($ 49,098)
Contracts realized or otherwise settled			(38,531)
Increase in gas and oil prices on futures markets			(16,174)
Contracts added since December 31, 2003			(61,498)
Net fair value of gas- and oil-hedging contracts outstanding at September 30, 2004			($165,301)

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

	(in thousands)

Contracts maturing by September 30, 2005	($125,063)
Contracts maturing between September 30, 2005, and September 30, 2006	(36,700)
Contracts maturing between September 30, 2006, and September 30, 2007	(3,593)
Contracts maturing after September 30, 2007	55
Net fair value of gas- and oil-hedging contracts at September 30, 2004	($165,301)

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 September 30,
	2004	2003
	(in millions)

Mark-to-market valuation – asset (liability)	($165.3)	($28.5)
Value if market prices of gas and oil decline by 10%	(91.4)	6.0
Value if market prices of gas and oil increase by 10%	(239.2)	(63.1)

Interest-Rate Risk Management

As of September 30, 2004, Market Resources had $350 million of fixed-rate long-term debt and no variable-rate long-term debt.

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.

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

Item 6.

Exhibits and Reports on Form 8-K.

The following exhibits are filed as part of this report.

Exhibit No.

Exhibit

4.5.

First Amendment to Credit Agreement dated October 25, 2004, by and among the Company and Bank of America N.A., and other lenders.

31.1.

Certification signed by Charles B. Stanley, the Company's Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2.

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

The Company did not file any Current Reports on Form 8-K during the third quarter of 2004.

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 MARKET RESOURCES, INC.

(Registrant)

November 12, 2004

/s/C. B. Stanley

Date

C. B. Stanley

President and Chief Executive Officer

November 12, 2004

/s/S. E. Parks

Date

S. E. Parks

Vice President and Chief Financial Officer

Exhibits List

Exhibit No.

Exhibit

4.5.

First Amendment to Credit Agreement dated October 25, 2004, by and among the Company and Bank of America N.A., and other lenders.

31.1.

Certification signed by C. B. Stanley, the Company's Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

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

Exhibit 4.5.

FIRST AMENDMENT TO CREDIT AGREEMENT

THIS FIRST AMENDMENT TO CREDIT AGREEMENT (herein called the “Amendment”) made as of October 25, 2004 by and among QUESTAR MARKET RESOURCES, INC., a Utah corporation (“Borrower”), BANK OF AMERICA, N.A., individually and as administrative agent (“Administrative Agent”), and the Lenders party to the Original Agreement defined below (“Lenders”).

W I T N E S S E T H:

WHEREAS, Borrower, Administrative Agent and Lenders entered into that certain Credit Agreement dated as of March 19, 2004 (the “Original Agreement”), for the purpose and consideration therein expressed, whereby Lenders became obligated to make loans to Borrower as therein provided; and

WHEREAS, Borrower, Administrative Agent and Lenders desire to amend the Original Agreement as set forth herein;

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement, in consideration of the loans which may hereafter be made by Lenders to Borrower, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows:

ARTICLE I.

DEFINITIONS AND REFERENCES

Section 1.1.

Terms Defined in the Original Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this Amendment.

Section 1.2.

Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this Section 1.2.

“Amendment” means this First Amendment to Credit Agreement.

“Credit Agreement” means the Original Agreement as amended hereby.

ARTICLE II.

AMENDMENT TO ORIGINAL AGREEMENT

Section 2.1.

Swap Contracts. Clause (B) of subsection (i) of Section 7.10 of the Original Agreement is hereby amended in its entirety to read as follows:

“(B)

such contracts do not require any Loan Party to provide any Lien on any property to secure the Loan Parties’ obligations thereunder, other than Liens on cash or cash equivalents and letters of credit; provided that the aggregate amount of cash and cash equivalents subject to Liens securing such contracts and the undrawn amount of all letters of credit securing such contracts shall not exceed $200,000,000 at any time.”

Section 2.2.

Waiver. Any violations of Section 7.10(i)(B) of the Original Agreement that occurred prior to the date hereof and any Default or Event of Default arising solely as a result of any such violations are hereby waived.

ARTICLE III.

CONDITIONS OF EFFECTIVENESS

Section 3.1.

Effective Date. This Amendment shall become effective as of the date first above written when and only when:

(a)

Administrative Agent shall have received all of the following, at Administrative Agent's office, duly executed and delivered and in form and substance satisfactory to Administrative Agent:

(i)

this Amendment;

(ii)

a certificate of the Secretary of Borrower dated the date of this Amendment certifying: (i) that resolutions adopted by the Board of Directors of the Borrower authorize the execution, delivery and performance of this Amendment by Borrower; (ii) the names and true signatures of the officers of the Borrower authorized to sign this Amendment; and (iii) that all of the representations and warranties set forth in Article IV hereof are true and correct at and as of the time of such effectiveness; and

(iii)

such other supporting documents as Administrative Agent may reasonably request.

(b)

Borrower shall have paid, in connection with such Loan Documents, all recording, handling, amendment and other fees required to be paid to Administrative Agent pursuant to any Loan Documents.

(c)

Borrower shall have paid, in connection with such Loan Documents, all other fees and reimbursements to be paid to Administrative Agent pursuant to any Loan Documents, or otherwise due Administrative Agent and including fees and disbursements of Administrative Agent's attorneys.

ARTICLE IV.

REPRESENTATIONS AND WARRANTIES

Section 4.1.

Representations and Warranties of Borrower. In order to induce each Lender to enter into this Amendment, Borrower represents and warrants to each Lender that:

(a)

The representations and warranties contained in Article V of the Original Agreement are true and correct at and as of the time of the effectiveness hereof, except to the extent that the facts on which such representations and warranties are based have been changed by the extension of credit under the Credit Agreement.

(b)

Borrower is duly authorized to execute and deliver this Amendment and is and will continue to be duly authorized to borrow monies and to perform its obligations under the Credit Agreement. Borrower has duly taken all corporate action necessary to authorize the execution and delivery of this Amendment and to authorize the performance of the obligations of Borrower hereunder.

(c)

The execution and delivery by Borrower of this Amendment, the performance by Borrower of its obligations hereunder and the consummation of the transactions contemplated hereby do not and will not conflict with any provision of law, statute, rule or regulation or of the articles of incorporation and bylaws of Borrower, or of any material agreement, judgment, license, order or permit applicable to or binding upon Borrower, or result in the creation of any lien, charge or encumbrance upon any assets or properties of Borrower. Except for those which have been obtained, no consent, approval, authorization or order of any court or governmental authority or third party is required in connection with the execution and delivery by Borrower of this Amendment or to consummate the transactions contemplated hereby.

(d)

When duly executed and delivered, each of this Amendment and the Credit Agreement will be a legal and binding obligation of Borrower, enforceable in accordance with its terms, except as limited by bankruptcy, insolvency or similar laws of general application relating to the enforcement of creditors' rights and by equitable principles of general application.

(e)

The audited annual consolidated financial statements of Borrower dated as of December 31, 2003 and the unaudited quarterly consolidated financial statements of Borrower dated as of June 30, 2004 fairly present the consolidated financial position at such dates and the consolidated statement of operations and the changes in consolidated financial position for the periods ending on such dates for Borrower. Copies of such financial statements have heretofore been delivered to each Lender. Since such dates no material adverse change has occurred in the consolidated financial condition or businesses of Borrower.

ARTICLE V.

MISCELLANEOUS

Section 5.1.

Ratification of Agreements. The Original Agreement as hereby amended is hereby ratified and confirmed in all respects. Any reference to the Credit Agreement in any Loan Document shall be deemed to be a reference to the Original Agreement as hereby amended. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of Lenders under the Credit Agreement, the Notes, or any other Loan Document nor constitute a waiver of any provision of the Credit Agreement, the Notes or any other Loan Document.

Section 5.2.

Survival of Agreements. All representations, warranties, covenants and agreements of Borrower herein shall survive the execution and delivery of this Amendment and the performance hereof, including without limitation the making or granting of the Loans, and shall further survive until all of the Obligations are paid in full. All statements and agreements contained in any certificate or instrument delivered by Borrower hereunder or under the Credit Agreement to any Lender shall be deemed to constitute representations and warranties by, and/or agreements and covenants of, Borrower under this Amendment and under the Credit Agreement.

Section 5.3.

Loan Documents. This Amendment is a Loan Document, and all provisions in the Credit Agreement pertaining to Loan Documents apply hereto.

Section 5.4.

Governing Law. This Amendment shall be governed by and construed in accordance the laws of the State of New York and any applicable laws of the United States of America in all respects, including construction, validity and performance.

Section 5.5.

Counterparts; Fax. This Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. This Amendment may be validly executed by facsimile or other electronic transmission.

THIS AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS OF THE PARTIES.

[THE REMAINDER OF THIS PAGE HAS BEEN INTENTIONALLY LEFT BLANK.]

IN WITNESS WHEREOF, this Amendment is executed as of the date first above written.

QUESTAR MARKET RESOURCES, INC.

By:

Name:

Title:

BANK OF AMERICA, N.A., as

Administrative Agent

By:

Name:

Title:

BANK OF AMERICA, N.A., as a Lender and L/C Issuer

By:

Name:

Title:

HARRIS NESBITT FINANCING, INC., as a Lender

By:

Name:

Title:

WELLS FARGO BANK, NA, as Co-Syndication Agent and a Lender

By:

Name:

Title:

SUNTRUST BANKS, INC., as
Co-Documentation Agent and a Lender

By:

Name:

Title:

BANK ONE, NA, as Co-Documentation Agent and a Lender

By:

Name:

Title:

WACHOVIA BANK, NATIONAL ASSOCIATION, as a Lender

By:

Name:

Title:

THE BANK OF TOKYO-MITSUBISHI, LTD., as a Lender

By:

Name:

Title:

BARCLAYS BANK PLC, as a Lender

By:

Name:

Title:

THE ROYAL BANK OF SCOTLAND plc, as a Lender

By:

Name:

Title:

U.S. BANK NATIONAL ASSOCIATION, as a Lender

By:

Name:

Title:

Exhibit No. 31.1.

CERTIFICATION

I, Charles B. Stanley, certify that:

I have reviewed this quarterly report on Form 10-Q of Questar Market Resources, Inc.

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.

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.

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:

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;

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

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;

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);

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

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

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

November 12, 2004

/s/C. B. Stanley___________________________

Date

C. B. Stanley

President and Chief Executive Officer

Exhibit No. 31.2.

CERTIFICATION

I, S. E. Parks, certify that:

I have reviewed this quarterly report on Form 10-Q of Questar Market Resources, Inc.

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

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;

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

November 12, 2004

/s/S. E. Parks___________________________

Date

S. E. Parks

Vice President and Chief Financial Officer