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 quarter ended September 30, 2005

[  ]

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 charter)

    STATE OF UTAH                                                                                             87-0287750

(State of other jurisdiction of                                                            (I.R.S. Employer

incorporation or organization)                                                          Identification No.)

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

Registrant’s telephone number, including area code (801) 324-2600

                                  Not Applicable                                  
(Former name or former address, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 of 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 by check mark whether the registrant is a shell company (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, 2005

       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, 2005

TABLE OF CONTENTS

Page No.

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   ended September 30, 2005 and 2004

8

   and December 31, 2004

9

   ended September 30, 2005 and 2004

10

11

   Results of Operations

15

23

25

26

26

26

26

NATURE OF BUSINESS

Questar Market Resources, Inc. (Market Resources or the Company) is a wholly owned subsidiary of Questar Corporation (Questar) and is Questar’s primary growth driver. Market Resources has four principal subsidiaries: Questar Exploration and Production Company (Questar E&P) explores for, acquires, develops and produces natural gas and oil; Wexpro Company (Wexpro) develops and produces cost-of-service reserves for an affiliated company, Questar Gas Company (Questar Gas); Questar Gas Management Company (Gas Management) provides gas-gathering and processing services for affiliates and third parties; and Questar Energy Trading Company (Energy Trading) markets equity and third-party natural gas and oil, provides risk-management services and, through Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir.

Market Resources operates in the Rocky Mountain and Midcontinent regions of the United States of America and is headquartered in Salt Lake City, Utah.  

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

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 Market Resources’ 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, but are not limited to, the following:

Market Resources’ subsidiaries find, produce and sell natural gas, oil and natural gas liquids (NGL)

Natural gas, oil and NGL prices are volatile and, therefore, Market Resources’ revenues, cash flow and earnings can be volatile. The Company cannot predict future natural gas, oil and NGL price movements, which are subject to forces beyond its control such as:

•

Domestic and foreign supply of and demand for natural gas and oil;

•

Regional basis differential due to pipeline-capacity constraints;

•

Domestic and global economic conditions;

•

Weather;

•

Domestic and foreign government regulations;

•

The price and availability of alternative fuels; and

•

The costs and availability of drilling rigs and other materials and services.

The Company uses financial contracts to hedge its exposure to volatile natural gas, oil and NGL prices and to protect cash flow, returns on capital, net income and credit ratings from downward commodity-price movements. While hedging reduces the impact of declining prices, it may also limit future revenues from favorable price movements. Market Resources believes its Wexpro subsidiary generates revenues that are not significantly sensitive to short-term fluctuations in natural gas, oil and NGL prices.

Market Resources’ profitability depends not only on prevailing prices for natural gas, oil and NGL, but also the Company’s ability to find, develop and acquire gas and oil reserves that are economically recoverable. Substantial capital expenditures are required to find, develop and acquire gas and oil reserves to replace those depleted by production.

Estimating gas and oil reserves, production and future net cash flow is difficult

Questar E&P’s proved natural gas and oil reserve estimates are prepared annually by independent reservoir-engineering consultants. Gas and oil reserve estimates are subject to numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and timing of development expenditures. The accuracy of these estimates depends on the quality of available data and on engineering and geological interpretation and judgment. Reserve estimates are imprecise and will change as additional information becomes available. Estimates of economically recoverable reserves and 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 change. The volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The meaningfulness of such estimates depends on the accuracy of the assumptions upon which they were based. Actual results may differ materially from the estimated results.

Drilling is a high-risk activity

Operating risks include: blow-outs; fire; unexpected drilling conditions such as uncontrollable flows of gas, oil, formation water or drilling fluids; abandonment costs; explosions; pipe, cement or casing failures; oil spills; natural gas leaks; and discharges of toxic gases. The Company could incur substantial losses as a result of injury or loss of life; environmental damage; destruction of property; fines; or curtailment of operations. The Company maintains insurance against some, but not all, of these potential risks and losses.

Market Resources must comply with numerous regulations from the federal, state and local level

Market Resources is subject to federal, state and local environmental, health and safety laws and regulations. Environmental laws and regulations are complex, change frequently and have become more onerous over time. In addition to the costs of compliance, the Company may incur substantial costs to take corrective actions at both owned and previously owned facilities. Accidental spills and leaks requiring cleanup may occur in the ordinary course of business. As standards change the Company may incur significant costs in cases where past operations followed practices that were considered acceptable at the time but that now require remedial work to meet current standards. Failure to comply with these laws and regulations may result in fines, significant costs for remedial activities, or injunctions.

Market Resources must comply with numerous and complex regulations governing activities on federal and state lands in the Rocky Mountain region, notably the National Environmental Policy Act, the Endangered Species Act and the National Historic Preservation Act. Federal and state agencies frequently impose conditions on the Company’s activities. These restrictions tend to become more stringent over time, and can limit or prevent the Company from exploring for, finding and producing natural gas, oil and NGL on its Rockies leaseholds. Certain environmental groups oppose drilling on some of the Company’s federal and state leases.

Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations include such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition each Native American tribe is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Finally, lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. One or more of these factors may increase Market Resources’ costs of doing business on Native American tribal lands and have an impact on the viability of its gas and oil operations on such lands.

Other factors may affect Market Resources results

Other factors may affect Market Resources results such as: changes in general economic conditions; changes in regulation; 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; 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; changes in credit ratings; and availability of financing.

The Company cannot predict these factors nor can it assess the impact, if any, of such factors on its financial position or its results of operations. Accordingly forward-looking statements should not be relied upon as a predictor of actual results. Market Resources undertakes no obligation to update any forward-looking statement provided in this report.

GLOSSARY OF COMMONLY USED TERMS

bbl

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

basis

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

bcf

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

bcfe

One billion cubic feet of natural gas equivalents. 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 at sea level.

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.

cf

Cubic foot is a common unit of gas measurement. One standard cubic foot equals the volume of gas in one cubic foot measured at standard conditions – a temperature of 60 degrees Fahrenheit and a pressure of 30 inches of mercury (approximately 14.7 pounds per square inch).    

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 production exceed 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 prospect to determine the presence of gas or oil.

finding costs

Finding costs are the sum of costs incurred for gas and oil exploration and development activities; including leasehold acquisitions, seismic, geological and geophysical, development and exploration drilling and asset-retirement obligations for a given period, divided by the total amount of estimated net proved reserves added through discoveries, positive and negative revisions of previous estimates and purchases in place for the same period. The Company expresses finding costs in dollars per Mcfe averaged over a five-year period.

frac spread

The difference in sales price of NGL’s extracted from the gas stream and the prices of a Btu-equivalent volume of gas to replace the extracted liquids.

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.

gas

   All references to “gas” in this report refer to natural gas.

gross

“Gross” natural gas and oil wells or “gross” acres equal the total number of wells or acres in which the Company has a working 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

Mdthe

One thousand decatherms of natural gas 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.

MMgal

One million U. S. gallons.

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 the sum of the fractional ownership working interest the Company has in those gross wells or acres.

production

The production replacement ratio is calculated by dividing the net proved reserves

replacement ratio

added through discoveries, positive and negative revisions of previous estimates and purchases and sales in place for a given period by the production for the same period, expressed as a percentage. The production replacement ratio is typically reported on an annual basis.

proved reserves

Those quantities of natural gas, crude oil, condensate and NGL on a net revenue interest basis, which geological and engineering data demonstrate with reasonable certainty to be recoverable under existing economic and operating conditions. See 17 C.F.R. Section 4-10(a)(2) for a complete definition.

proved developed

Reserves that include proved developed producing reserves and proved developed

reserves

behind pipe reserves. See 17 C.F.R. Section 4-10(a)(3).

proved developed

Reserves expected to be recovered from existing completion intervals in existing

producing reserves

wells.

proved undeveloped

Reserves expected to be recovered from new wells on proved undrilled acreage or

reserves

from existing wells where a relatively major expenditure is required for recompletion. See 17 C.F.R. Section 4-10(a)(4).

psia

Equals gauge pressure (see psig) plus local atmospheric pressure (in pounds per square inch). At sea level and standard temperature the absolute pressure is 14.7 pounds per square inch.

psig

Pounds per square inch gauge. The pressure in pounds per square inch as measured by a gauge.

reservoir

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

wet gas

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

working interest

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

SEC FILINGS AND WEBSITE INFORMATION

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

Investors can also access financial and other information for Market Resources through Questar’s website at www.questar.com. Questar’s website contains Statements of Responsibility for Board Committees, Corporate Governance Guidelines and its Business Ethics and Compliance Policy.

Market Resources makes available, free of charge through the Questar website, copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to such reports. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC.

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,
	2005	2004	2005	2004
	(in thousands)
REVENUES
From unaffiliated customers	$446,746	$255,264	$1,105,980	$733,678
From affiliates	34,746	29,333	108,571	97,780
TOTAL REVENUES	481,492	284,597	1,214,551	831,458
OPERATING EXPENSES
Cost of natural gas and other products sold	243,972	121,885	559,201	337,765
Operating and maintenance	55,554	41,568	151,909	119,935
Production and other taxes	25,413	17,180	67,619	52,332
Depreciation, depletion and amortization	44,083	34,238	125,199	105,271
Exploration	2,574	1,346	9,423	3,699
Abandonment and impairment of gas,
oil and other properties	1,712	2,848	4,610	9,541
Wexpro Agreement – oil-income sharing	1,770	1,101	4,395	3,249
TOTAL OPERATING EXPENSES	375,078	220,166	922,356	631,792
OPERATING INCOME	106,414	64,431	292,195	199,666
Interest and other income	3,609	459	4,960	1,202
Earnings from unconsolidated affiliates	1,910	1,021	5,131	3,595
Debt expense	(8,546)	(6,728)	(22,356)	(20,602)
INCOME BEFORE INCOME TAXES	103,387	59,183	279,930	183,861
Income taxes	38,108	21,972	103,269	68,232
NET INCOME	$  65,279	$  37,211	$   176,661	$115,629

See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,	December 31,
	2005	2004
	(Unaudited)
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$       8,601
Notes receivable from Questar	6,400	$     49,400
Accounts receivable, net	216,480	174,539
Accounts receivable from affiliates	19,458	19,247
Hedging collateral deposits	243,270
Fair value of hedging contracts	30	9,334
Inventory, at lower of cost or market
Gas and oil storage	26,012	22,604
Materials and supplies	22,090	8,631
Prepaid expenses and other	16,558	16,632
Deferred income taxes – current	158,899	20,592
Total current assets	717,798	320,979
Property, plant and equipment	2,840,259	2,456,332
Less accumulated depreciation, depletion      and amortization	1,057,734	937,267
Net property, plant and equipment	1,782,525	1,519,065
Investment in unconsolidated affiliates	40,805	33,229
Goodwill	61,423	61,423
Other noncurrent assets	11,322	14,694
	$2,613,873	$1,949,390
Current liabilities
Checks in excess of cash balances		$       4,394
Notes payable to Questar	$    107,400	61,200
Accounts payable and accrued expenses	277,186	226,155
Accounts payable to affiliates	6,476	6,372
Fair value of hedging contracts	420,580	64,179
Total current liabilities	811,642	362,300
Long-term debt	550,000	350,000
Deferred income taxes	352,384	334,103
Asset-retirement obligations	71,758	66,375
Fair value of hedging contracts	147,545	14,471
Other long-term liabilities	38,725	33,271
Common shareholder’s equity
Common stock	4,309	4,309
Additional paid-in capital	116,027	116,027
Retained earnings	874,370	710,684
Accumulated other comprehensive loss	(352,887)	(42,150)
Total common shareholder’s equity	641,819	788,870
	$2,613,873	$1,949,390

See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	9 Months Ended
	September 30,
	2005	2004
	(in thousand)
OPERATING ACTIVITIES
Net income	$ 176,661	$ 115,629
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	125,786	108,666
Deferred income taxes	69,441	33,606
Abandonment and impairment of gas,
oil and other properties	4,610	9,541
Earnings from unconsolidated affiliates,
net of cash distributions	(789)	1,046
Net gain from asset sales	(974)	(91)
Hedge ineffectiveness and other	390	218
Changes in operating assets and liabilities	(259,928)	(25,556)
NET CASH PROVIDED FROM
OPERATING ACTIVITIES	115,197	243,059
INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(373,350)	(190,708)
Other investments	(6,787)	(1,000)
Total capital expenditures	(380,137)	(191,708)
Proceeds from disposition of assets	1,710	1,361
NET CASH USED IN INVESTING ACTIVITIES	(378,427)	(190,347)
FINANCING ACTIVITIES
Checks in excess of cash balances		9,702
Change in notes receivable from Questar	43,000	(8,800)
Change in notes payable to Questar	46,200	10,900
Long-term debt issued	200,000
Long-term debt repaid		(55,000)
Dividends paid	(12,975)	(12,975)
Other		(255)
NET CASH PROVIDED FROM (USED IN)       FINANCING ACTIVITIES	276,225	(56,428)
Change in cash and cash equivalents	12,995	(3,716)
Beginning cash and cash equivalents (checks in       excess of cash balances)	(4,394)	3,716
Ending cash and cash equivalents	$     8,601	$            -

See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation of Interim Consolidated Financial Statements

The accompanying interim consolidated financial statements of Market Resources have not been audited by an independent registered public accounting firm, with the exception of the condensed consolidated balance sheet at December 31, 2004, which was derived from the audited consolidated financial statements at that date. The unaudited consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) for interim financial information and with the SEC’s instructions for Form 10-Q. 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 financial position and 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 2004 financial statements to conform with the 2005 presentation.

The results of operations for the nine months ended September 30, 2005, are not necessarily indicative of the results that may be expected for the year ending December 31, 2005, due to a variety of factors discussed in the Forward-Looking Statements and Risk Factors 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, 2004.

Note 2 – Asset-Retirement Obligations (ARO)

Market Resources recognizes ARO in accordance with 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 Company’s ARO applies primarily to plugging and abandonment costs associated with gas and oil wells and certain other properties. The fair value of abandonment costs are estimated and depreciated over the life of the related assets. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Changes in asset-retirement obligations were as follows:

	2005	2004
	(in thousands)
Balance at January 1,	$66,375	$60,493
Accretion	3,097	1,847
Additions	3,010	1,593
Revisions		695
Retirements and properties sold	(724)	(365)
Balance at September 30,	$71,758	$64,263

Wexpro activities are governed by a long-standing agreement with the states of Utah and Wyoming (the Wexpro Agreement). The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is spelled out in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the Public Service Commission of Wyoming. Pursuant to the stipulation, Wexpro collects and deposits in trust certain funds related to estimated ARO costs. The funds are used to satisfy retirement obligations as the properties are abandoned. At September 30, 2005, approximately $3.6 million was held in this trust invested in a short-term bond index fund.

Note 3 – 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, 2005, were: Rendezvous Gas Services, LLC (Rendezvous), a limited liability corporation, (50%) and Canyon Creek Compression Co., a general partnership (15%). Operating results representing 100% of these businesses are listed below.

	9 Months Ended
	September 30,
	2005	2004
	(in thousands)
Revenues	$15,547	$12,222
Operating income	10,059	7,309
Income before income taxes	10,154	7,325

Note 4 - Operations by Line of Business

Market Resources has four primary reportable segments: Questar E&P, Wexpro, Gas Management and 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. Certain intersegment sales include intercompany profits. Financial information for reportable segments follow:

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(in thousands)
REVENUES FROM UNAFFILIATED CUSTOMERS
Questar E&P	$158,269	$107,823	$   428,116	$322,890
Wexpro	6,228	3,969	14,779	12,170
Gas Management	35,561	22,528	97,743	62,680
Energy Trading and other	246,688	120,944	565,342	335,938
	$446,746	$255,264	$1,105,980	$733,678
REVENUES FROM AFFILIATES
Wexpro	$  31,657	$  26,640	$     97,845	$  86,054
Gas Management	3,003	2,681	9,204	8,321
Energy Trading and other	86	12	1,522	3,405
	$  34,746	$  29,333	$   108,571	$  97,780

OPERATING INCOME  (LOSS)
Questar E&P	$  76,405	$  44,831	$   200,365	$136,157
Wexpro	16,850	13,578	48,599	42,143
Gas Management	10,281	7,282	36,339	21,053
Energy Trading and other	2,878	(1,260)	6,892	313
	$106,414	$  64,431	$   292,195	$199,666
NET INCOME (LOSS)
Questar E&P	$  44,753	$  24,783	$   115,430	$  75,406
Wexpro	11,251	8,737	31,928	26,552
Gas Management	7,299	4,768	25,069	14,228
Energy Trading and other	1,976	(1,077)	4,234	(557)
	$  65,279	$  37,211	$   176,661	$115,629

Note 5 – 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. These results are not reported in current income or loss. Income or loss is realized when the physical gas or oil underlying the derivative instrument is sold. A summary of comprehensive income is shown below:

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(in thousands)
Net income	$   65,279	$   37,211	$176,661	$ 115,629
Other comprehensive loss
Unrealized loss on energy hedging transactions	(352,386)	(49,269)	(500,204)	(113,858)
Income taxes	133,237	18,440	189,467	42,641
Net other comprehensive loss	(219,149)	(30,829)	(310,737)	(71,217)
Total comprehensive income (loss)	($153,870)	$     6,382	($134,076)	$   44,412

Note 6 – Recent Accounting Developments

In July 2005 the Financial Accounting Standards Board (FASB) issued an exposure draft of a Proposed Interpretation “Accounting for Uncertain Tax Positions,” an Interpretation of FASB Statement 109. The exposure draft seeks to reduce perceived diversity in practice associated with recognition and measurement in the accounting for income taxes. The exposure draft would apply to all tax positions accounted for in accordance with SFAS 109 “Accounting for Income Taxes.” The exposure draft requires that a tax position meet a “probable recognition threshold” for the benefit of the uncertain tax position to be recognized in the financial statements. This threshold is to be met assuming that the tax authorities will examine the uncertain tax position. The exposure draft contains guidance with respect to the measurement of the benefit that is recognized for an uncertain tax position, when that benefit should be derecognized, and other matters. This interpretation will be effective for Market Resources beginning January 1, 2006, under the timeframe in the proposed statement. The Company has not evaluated the potential effect of this proposed change in accounting principle.

Questar has granted and may continue to grant stock-based compensation to certain Market Resources employees. In December 2004 the FASB issued Statement 123 (revised 2004), (SFAS 123R), “Share Based Payment,” which replaces SFAS 123 and supersedes APB Opinion 25. SFAS 123R eliminates the alternative to use APB Opinion 25’s intrinsic value method of accounting that was provided in SFAS 123 as originally issued. After a phase-in period for SFAS 123R, pro forma disclosure will no longer be allowed. The effective date for implementation of SFAS 123R is January 1, 2006. Alternative phase-in methods are allowed under SFAS 123R. Questar currently anticipates using the modified prospective phase-in method that requires recognition of compensation costs for all share based payments granted, modified or settled after the date of implementation as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. The Company believes none of the alternative phase-in methods will have a material effect on operating results or financial position.

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Unaudited)

SUMMARY

Market Resources net income for the third quarter of 2005 was $65.3 million compared with $37.2 million for the year earlier period, a 75% increase. Net income for the first nine months of 2005 totaled $176.7 million versus $115.6 million for the same period in 2004, a 53% increase. Operating income increased $42.0 million, or 65%, in the quarter to quarter comparison, and $92.5 million, or 46%, in the nine month comparison due primarily to higher commodity prices and increased natural gas production at Questar E&P, an increased investment base at Wexpro, and increased NGL volumes coupled with improved gas gathering and processing margins at Gas Management. Following is a comparison of net income (loss) by line of business:

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(in thousands)
Net income (loss)
Questar E & P	$44,753	$24,783	$115,430	$75,406
Wexpro	11,251	8,737	31,928	26,552
Gas Management	7,299	4,768	25,069	14,228
Energy Trading and other	1,976	(1,077)	4,234	(557)
Total	$65,279	$37,211	$176,661	$115,629

RESULTS OF OPERATIONS

Following is a summary of Market Resources’ financial and operating results for the third quarter and first nine months of 2005 compared with the same periods of 2004:  

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(in thousands)
OPERATING INCOME
Revenues
Natural gas sales	$131,466	$  88,799	$352,985	$268,495
Oil and NGL sales	31,254	21,933	86,178	63,151
Cost-of-service gas operations	32,051	27,307	97,704	87,753
Energy marketing	248,069	121,792	568,979	340,733
Gas gathering, processing and other	38,652	24,766	108,705	71,326
Total revenues	481,492	284,597	1,214,551	831,458
Operating expenses
Energy purchases	243,972	121,885	559,201	337,765
Operating and maintenance	55,554	41,568	151,909	119,935
Production and other taxes	25,413	17,180	67,619	52,332
Depreciation, depletion and amortization	44,083	34,238	125,199	105,271
Exploration	2,574	1,346	9,423	3,699
Abandonment and impairment of gas,     oil and other properties	1,712	2,848	4,610	9,541
Wexpro Agreement – oil-income sharing	1,770	1,101	4,395	3,249
Total operating expenses	375,078	220,166	922,356	631,792
Operating income	$106,414	$ 64,431	$292,195	$199,666
OPERATING STATISTICS
Questar E&P production volumes
Natural gas (MMcf)	25,681	21,831	71,930	65,546
Oil and NGL (Mbbl)	593	571	1,762	1,717
Total production (bcfe)	29.2	25.3	82.5	75.8
Average daily production (MMcfe)	318	275	302	277
Average commodity prices, net to the well
Average realized price (including hedges)
Natural gas (per Mcf)	$     5.12	$      4.07	$       4.91	$     4.10
Oil and NGL (per bbl)	$   43.04	$    31.83	$     40.61	$   30.28
Average sales price (excluding hedges)
Natural gas (per Mcf)	$     6.66	$      4.92	$       5.89	$     4.89
Oil and NGL (per bbl)	$   57.65	$    40.55	$     50.62	$   35.89
Wexpro investment base at September 30, net
of depreciation and deferred income      taxes (millions)	$   197.6	$    165.0
Natural gas gathering volumes (in thousands      of MMBtu)
For unaffiliated customers	35,619	32,767	101,693	99,225
For Questar Gas	10,252	8,915	32,734	27,821
For other affiliated customers	17,895	12,995	48,157	40,889
Total gathering	63,766	54,677	182,584	167,935
Gathering revenue (per MMBtu)	$     0.25	$     0.22	$      0.25	$      0.21
Natural gas and oil marketing volumes (Mdthe)
For unaffiliated customers	32,064	24,973	87,320	66,303
For affiliated customers	22,455	20,188	67,102	61,234
Total marketing	54,519	45,161	154,422	127,537

Questar E&P

For the third quarter of 2005, Questar E&P net income increased 81% to $44.8 million compared with $24.8 million for the same period in 2004. Net income for the first nine months of 2005 was $115.4 million versus $75.4 million for the same period in 2004, a 53% increase. The increases were driven by a combination of higher realized natural gas, oil and NGL prices and increased gas, oil and NGL production volumes.

Questar E&P’s production increased to 29.2 bcfe in the third quarter of 2005, a 16% increase compared to the year-earlier period. Production for the first nine months of 2005 was 82.5 bcfe versus 75.8 bcfe for the 2004 period, a 9% increase. Current year production was negatively impacted by weather-related completion and workover delays on Uinta Basin and western Midcontinent properties during the first quarter, construction and maintenance-related curtailments on an interstate pipeline serving the Uinta Basin during the third quarter, and delays caused by seasonal access restrictions on Rockies Legacy properties. Seasonal access restrictions exist over much of Market Resources’ federal leasehold acreage in the Rockies. Delays in obtaining rigs to drill planned development wells in the western Midcontinent also impacted first nine months 2005 production growth.

Natural gas is Questar E&P’s primary focus. On an energy-equivalent basis, natural gas comprised approximately 87% of Questar E&P’s production for the first nine months of 2005. A comparison of energy equivalent production by region is shown in the following table:

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(in bcfe)
Rocky Mountains
Pinedale Anticline	8.7	5.1	22.8	16.0
Uinta Basin	6.6	6.4	19.2	18.8
Rockies Legacy	4.3	4.3	12.3	13.5
Subtotal – Rocky Mountains	19.6	15.8	54.3	48.3
Midcontinent	9.6	9.5	28.2	27.5
Total Questar E&P production	29.2	25.3	82.5	75.8

Questar E&P’s first nine months 2005 production from the Pinedale Anticline in western Wyoming increased 42% to 22.8 bcfe versus 16.0 bcfe in the first nine months of 2004. Production at Pinedale typically declines during the first through third quarters of each year due to mid-November to early May seasonal access restrictions imposed by the Bureau of Land Management (BLM) that restrict the company’s ability to drill and complete wells during the period.

In the Uinta Basin of eastern Utah, Questar E&P production increased 2% to 19.2 bcfe in the first nine months of 2005 compared to 18.8 bcfe a year ago. Third quarter 2005 production was reduced by construction and maintenance on an interstate pipeline that serves the area.

Production from Questar E&P’s Rockies Legacy properties in the first nine months of 2005 was 12.3 bcfe compared to 13.5 bcfe during the 2004 period, an 8% decrease. Legacy properties include all of Questar E&P’s Rocky Mountain producing properties other than Pinedale and the Uinta Basin. Legacy properties production during the 2005 period was negatively impacted by normal field decline, seasonal restrictions that limit access to leases and wells during the winter months, payout of a high-volume well that reduced the company’s working interest and mechanical problems that delayed completion of a new well in the Vermillion Basin.

Midcontinent production was 28.2 bcfe in the first nine months of 2005 compared to 27.5 bcfe for the same period of 2004, a 2% increase. The company continued one-rig-development programs in both the Hartshorne coalbed-methane development project in the Arkoma Basin of eastern Oklahoma and the ongoing infill-development drilling on the Elm Grove properties in northwest Louisiana.

Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. For the first nine months of 2005, the weighted average realized natural gas price for Questar E&P (including the effects of hedging) was $4.91 per Mcf compared to $4.10 per Mcf for the same period in 2004, a 20% increase. Realized oil and NGL prices for the first nine months of 2005 averaged $40.61 per bbl, compared with $30.28 per bbl during the prior year period, a 34% increase. A comparison of average realized prices by region, including hedges, is shown in the following table:

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
Natural gas (per Mcf)
Rocky Mountains	$  4.94	$  3.79	$  4.73	$  3.86
Midcontinent	5.47	4.50	5.23	4.50
Volume-weighted average	$  5.12	$  4.07	$  4.91	$  4.10
Oil and NGL (per bbl)
Rocky Mountains	$44.13	$31.15	$41.38	$29.48
Midcontinent	40.34	33.50	38.84	32.15
Volume-weighted average	$43.04	$31.83	$40.61	$30.28

Approximately 81% of Questar E&P’s gas production in the third quarter of 2005 was hedged or pre-sold. For the first nine months of 2005, approximately 84% was hedged or pre-sold. Hedging reduced gas revenues $39.6 million and $70.7 million during the third quarter and first nine months of 2005, respectively. For the current quarter, Questar E&P also hedged approximately 73% of its oil production. For the first nine months 2005, approximately 67% was hedged or pre-sold. Oil hedges reduced revenues $8.7 million and $17.6 million during the third quarter and first nine months of 2005, respectively.

Market Resources may hedge up to 100 percent of its forecasted production from proved developed reserves to lock in acceptable returns on invested capital and to protect cash flow and earnings from a decline in commodity prices. Questar E&P has continued to take advantage of high natural gas and oil prices to add to its hedge positions through 2008. Natural gas and oil hedges as of September 30, 2005, are summarized in Part I, Item 3 of this report.

Questar E&P’s pre-income tax cost structure per unit of production (the sum of depreciation, depletion and amortization expense, lifting costs, general and administrative expense and allocated-interest expense) increased 11% to $2.82 per Mcfe in the third quarter of 2005 versus $2.53 per Mcfe in the third quarter of 2004. For the first nine months of 2005, pre-income tax cost structure rose 12% to $2.77 per Mcfe compared to $2.48 per Mcfe in the first nine months of 2004.

Depreciation, depletion and amortization expense rose 12% in the third quarter to $1.19 per Mcfe and 14% to $1.17 per Mcfe for the first nine months of 2005 due to normal decline in production from older, lower cost successful-efforts pools, negative reserve revisions over the past 12 months at the company’s Uinta Basin properties and higher reserve replacement (finding and development) costs. Higher day rates for rigs and other services in core operating areas, along with sharply higher steel prices, resulted in higher drilling and completion costs.  

Increased production taxes and lease operating expenses drove a $0.17 per Mcfe increase in lifting costs during the current quarter and $0.14 per Mcfe in the first nine months of 2005 versus the comparable year-earlier periods. Increased production taxes were driven by higher gas, oil and NGL sales prices. Most production taxes are based on a fixed percentage of commodity sales prices. Higher lease operating expenses reflect a general increase in well service costs, including costs of contracted services and production-related supplies, increased workover and production enhancement projects and additional production-related costs.

For the third quarter of 2005, general and administrative expenses remained flat at $0.29 per Mcfe compared to the same period in 2004. For the first nine months of 2005, general and administrative expenses increased $0.01 per Mcfe, or 3% to $0.31 per Mcfe. The company continues to adjust employee compensation in response to industry competition for skilled professionals. Higher allocated corporate overhead (primarily employee benefits and compliance costs) also contributed to the increase. Questar E&P’s pre-income tax cost structure is summarized in the following table:

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(per Mcfe)
Lease-operating expense	$0.52	$0.52	$0.55	$0.51
Production taxes	0.61	0.44	0.53	0.43
Lifting costs	1.13	0.96	1.08	0.94
Depreciation, depletion and amortization	1.19	1.06	1.17	1.03
General and administrative expense	0.29	0.29	0.31	0.30
Allocated-interest expense	0.21	0.22	0.21	0.21
Total	$2.82	$2.53	$2.77	$2.48

Exploration expense increased $1.2 million in the third quarter and $5.4 million in the first nine months of 2005 compared to the 2004 periods. The increase in expense was due to $2.7 million of exploratory dry hole expense in the second quarter and increased exploratory seismic acquisition expenditures in the Midcontinent and Uinta Basin. Abandonment and impairment expense declined $1.1 million for the quarter and $4.9 million for the first nine months of 2005. The year to date decrease was primarily due to an impairment expense in the first quarter of 2004 resulting from a well with collapsed casing.

Pinedale Anticline

As of October 31, 2005, Market Resources (both Questar E&P and Wexpro) operated 136 producing wells on the Pinedale Anticline compared to 88 at the end of the third quarter of 2004, and 104 at year-end 2004. Of the 136 producing wells, Questar E&P has working interests in 120 wells, overriding royalty interests only in an additional 15 Wexpro-operated wells and no interest in one well operated by Wexpro. Wexpro has working interests in 54 of the 136 producing wells. Market Resources expects to complete about 35 Lance Pool wells (combined Lance and Mesaverde formations) on its Pinedale acreage during 2005.

On August 9, 2005, the Wyoming Oil and Gas Conservation Commission approved 10-acre-density drilling for Lance Pool wells on about 12,700 acres of Market Resources’ 18,208 acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the currently estimated productive limits of Market Resources’ core acreage in the field. With 10-acre-density drilling, the company currently believes that up to 932 wells will be required to fully develop the Lance Pool on its acreage.

On August 19, 2005, Questar E&P reached a total depth of 19,520 feet in the Hilliard Shale at the Stewart Point 15-29 exploratory well. Based on log information and gas shows, Questar E&P identified multiple zones of interest below the Lance Pool at depths from about 16,000 to 19,500 feet, ran casing to total depth and in mid-September commenced hydraulic-stimulation and testing. Starting in the lower part of the well, the company pumped three frac stages over a 900 foot interval from 18,541 to 19,434 feet and began flowing the well back to sales on an 18/64 inch choke. During initial flowback, the company measured extrapolated flow rates as high as 10.7 MMcf per day of dry, sweet gas with 10,000 to 12,000 psig flowing casing pressure and an extrapolated rate of about 2,400 barrels per day of frac water. As the flowback continued, the well exhibited steadily declining rates and pressures and, on several occasions, had to be shut in to remove debris plugging the choke. Eventually a combination of very small pieces of shale from the formation, proppant used in the fracs, and chunks of the flow-through frac plugs used to isolate individual stages partially filled the wellbore, blocking the flow of gas to the surface. The vertical extent of the obstruction is currently unknown. Given the very high formation pressures, specialized equipment (a high-pressure snubbing unit) and very experienced personnel are required to attempt to circulate out the rubble inside the wellbore and either re-establish production from the initial test interval, or isolate that interval and move up-hole to test additional zones. The company was not able to secure the right snubbing unit and crew for this operation before cold winter weather would make this operation technically and operationally risky. The resumption of testing of the well will be delayed until the spring of 2006.

Uinta Basin

During the first nine months of 2005, the company drilled or participated in six horizontal Green River formation oil wells, 44 Wasatch and Upper Mesaverde gas wells, and four deeper Blackhawk and Mancos formation gas wells on its core acreage block. In addition the company completed its first well in the Flat Rock area approximately 40 miles south of the core acreage block.

Questar E&P recently reached total depth on the Wolf Flat 1P-1-15-19 well, the first well drilled under an Exploration and Development Agreement (EDA) with the Ute Indian Tribe covering 12,557 acres of tribal minerals in the southern Uinta Basin. Logs indicate pay in multiple horizons. Completion operations should begin during the fourth quarter of 2005. Questar E&P has a 50% working interest in the Wolf Flat well. The company also recently completed acquisition of a 2-D seismic survey covering a portion of the EDA lands. Pursuant to the EDA Questar E&P has exercised its option to acquire leases on all of the EDA lands. The Ute Indian Tribe has the option to participate in the first well drilled in each section with up to a 50% working interest.

Rockies Legacy

In the Vermillion Basin on the southwest Wyoming-northwest Colorado border, Market Resources continues to evaluate the potential of several formations at depths of 10,000 to 15,000 feet under the company’s approximately 143,000 net leasehold acres. As of October 31, 2005, the company had recompleted two older wells, drilled and completed two new wells, had one well waiting on completion and was drilling one well. The first new well, Alkali Gulch Unit Well No 1, was completed in June 2005 and produced an average of 1.93 MMcf per day from the Baxter, Frontier and Dakota formations during the first 141 days. On October 31 the well was producing about 1.6 MMcf per day. The second new well, Canyon Creek 41, went to sales on September 21, 2005. During the first 30 days of production, the well averaged 2.95 MMcf per day from the Baxter and Frontier formations. The well was producing 1.9 MMcf per day on October 31, 2005. After delays related to mechanical problems, the third new well, Hiawatha Deep Unit No. 5 should be completed and turned to sales in mid-November 2005. The company currently plans to drill about 12 new wells in the Vermillion Basin in 2006.

Midcontinent

During the third quarter the company continued one-rig development programs at both the Hartshorne coalbed-methane project in the Arkoma Basin of eastern Oklahoma and the infill-development drilling project in the Elm Grove properties in northwestern Louisiana. The company drilled or participated in 26 new Hartshorne wells in the first nine months of 2005 and anticipates participating in an additional 11 wells in the fourth quarter of 2005. In the Elm Grove area, the company drilled or participated in 19 new wells through the first nine months of 2005 and eight additional wells are planned in the fourth quarter.

Wexpro

For the third quarter of 2005 Wexpro’s net income was $11.3 million, compared with $8.7 million for the same period in 2004, a 29% increase. For the first nine months of 2005 Wexpro’s net income was $31.9 million, compared with $26.6 million for the same period in 2004, a 20% increase. Wexpro develops and produces gas reserves on behalf of affiliate Questar Gas. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation (investment base). Wexpro’s investment base increased to $197.6 million at September 30, 2005, up $32.6 million over the year earlier period. Wexpro’s net income also benefited from higher oil and NGL prices in 2005.

Gas Management

Gas Management net income increased 53% to $7.3 million in the third quarter of 2005 from $4.8 million in the 2004 period. Net income for the first nine months of 2005 was $25.1 million versus $14.2 million for the same period in 2004, a 76% increase. Gross keep-whole processing margins (revenue from the sale of extracted NGL’s less the cost of natural gas to replace the Btu-equivalent of extracted NGL volumes and operating costs), grew 33% from $9.8 million in the first nine months of 2004 to $13.0 million in 2005. The first quarter 2005 acquisition of a gas plant in western Wyoming drove a 62% increase in extracted NGL volumes in the third quarter and 55% for the first nine months of 2005 versus the year earlier periods. Gathering volumes increased 14.6 million MMBtu to 182.6 million MMBtu in the first nine months of 2005 due primarily to expanding Pinedale production and new projects serving third parties in the Uinta Basin.

To reduce processing margin risk, Gas Management has restructured a number of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. (A keep-whole contract protects producers from frac spread risk while fee-based contracts eliminate commodity-price risk for the plant owner.) To further reduce margin volatility associated with keep-whole contracts, Gas Management began managing NGL price risk in 2004 by using forward-sales contracts. In the first nine months of 2005 keep-whole contracts benefited from a 16% increase in NGL sales prices versus the prior-year period. Fee-based contracts benefited from a $0.03 increase in the rate charged per MMBtu processed in the nine month comparable periods. Forward sales contracts decreased NGL revenues by $0.7 million in 2005.  

Earnings before tax from Gas Management’s 50% interest in Rendezvous Gas Services, LLC, (Rendezvous) increased to $5.0 million for the first nine months of 2005 versus $3.5 million for 2004, a 40% increase. Earnings growth in Rendezvous was driven by increased gathering volumes. Rendezvous provides gas gathering services for the Pinedale and Jonah producing areas. Gas Management continues to invest in additional gas gathering and processing and liquids-handling facilities to serve growing equity and third-party production in its core areas of the Pinedale and Jonah fields in western Wyoming and the Uinta Basin in eastern Utah.

During the first quarter 2005 Gas Management acquired a cryogenic gas processing facility located approximately 13 miles south of Gas Management’s Blacks Fork plant, adding approximately 60 MMcf per day of raw gas processing and NGL extraction capacity at its western Wyoming hub. The plant has been connected to the Blacks Fork/Granger complex to significantly enhance processing and blending capacity for Pinedale, Jonah and other western Wyoming producers served by Gas Management and Rendezvous.

Gas Management remains on schedule to complete and commission its condensate and produced-water gathering and transportation facilities on Market Resources’ Pinedale Anticline leasehold by mid-November, in time to satisfy BLM conditions for expanded winter access. These new facilities will eliminate over 25,500 tanker-truck trips per year at peak production from Market Resources’ operated acreage and the related air emissions, dust, noise, visual and traffic impacts.

Gas Management entered into an agreement with a third party producer to gather, compress and process gas in the Uinta Basin. Under terms of the fee-based agreement, the company constructed gas compression facilities and expanded its existing Red Wash gas plant to process an additional 70 MMcf per day of raw gas. The processed gas and liquids are redelivered to the producer. The new facilities were in-service at the end of the third quarter 2005. Gas Management has also signed a letter of intent to form a joint venture with the Ute Indian Tribe and another industry participant to build a gas gathering system for the Flat Rock area in southern Uinta Basin.

Energy Trading

Energy Trading’s net income for the third quarter of 2005 was $2.0 million compared to a loss of $1.1 million in 2004. For the first nine months of 2005, net income was $4.2 million compared to a loss of $0.6 million in 2004. Gross margins for gas and oil marketing (gross revenues less costs for gas and oil purchases, transportation and gas storage), increased to $9.8 million for the first nine months of 2005 versus $3.0 million a year ago, a 231% increase. The increase in gross margin was due primarily to a 178% higher unit margin and a 21% increase in volumes over the same period last year.

Consolidated Results After Operating Income

Earnings from unconsolidated affiliates

Gas Management has a 50% interest in Rendezvous, which provides gas-gathering services for the Pinedale and Jonah producing areas of western Wyoming. Gas Management’s share of Rendezvous’ earnings before tax increased to $1.9 million in the 2005 quarter versus $1.0 million in 2004 and $5.0 million in the first nine months of 2005 compared to $3.5 million for the same period last year. Rendezvous gathering volumes increased 80% in the third quarter and 48% in the first nine months of 2005 compared to the year earlier periods.

Debt expense

Debt expense rose in the third quarter of 2005 because the Company increased borrowings to meet hedging collateral calls precipitated by increases in natural gas and oil prices.

Interest and Other Income

Interest and other income was higher in the third quarter and first nine months of 2005 compared to the same periods of 2004. The income in the 2005 periods also reflects interest received on hedging collateral deposits. Gains from asset sales added $1.1 million before tax in the third quarter of 2005.

Income taxes

The effective combined federal and state income tax rate for the first nine months was 36.9% in 2005 and 37.1% in 2004.

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. Hedging contracts are used for a significant share of Questar E&P-owned gas and oil production and for a portion of gas- and oil-marketing transactions and for some of Gas Management’s NGL.

Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. Natural gas- and oil-price hedging supports Market Resources’ rate of return and cash-flow targets and protects 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 Company’s Board of Directors. Market Resources may hedge up to 100% of forecast 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 typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. Any ineffective portion of hedges is immediately recognized in income. The ineffective portion of hedges was not significant in 2005 and 2004.

As of September 30, 2005, approximately 22.6 bcf of forecast gas production for the remainder of 2005 was hedged at an estimated average price of $5.15 per Mcf, net to the well (which reflects assumed adjustments for regional basis, gathering and processing costs and gas quality).

Market Resources enters into commodity-price-hedging arrangements with several banks and energy-trading firms with a variety of credit requirements. Some contracts do not require collateral deposits, while others allow some amount of credit before Market Resources is required to deposit collateral for out-of-the-money hedges. The amount of credit available may vary depending on the credit rating assigned to Market Resources’ debt. In addition to the counterparty arrangements, Market Resources has a $200 million long-term revolving-credit facility with banks that was fully utilized at September 30, 2005.

A summary of Market Resources hedging positions for equity production as of September 30, 2005, is shown below. Prices are net to the well. Currently all hedges are fixed-price swaps with creditworthy counterparties, allowing Market Resources to achieve a known price for a specific volume of production delivered into a regional sales point. The swap price is then reduced by gathering costs and adjusted for product quality 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 2005	16.1	6.5	22.6	$5.12	$5.23	$5.15
First half of 2006	23.1	10.3	33.4	5.56	6.24	5.77
Second half of 2006	23.5	10.4	33.9	5.56	6.24	5.77
12 months of 2006	46.6	20.7	67.3	5.56	6.24	5.77
First half of 2007	11.4	7.6	19.0	6.40	7.40	6.80
Second half of 2007	11.5	7.7	19.2	6.40	7.40	6.80
12 months of 2007	22.9	15.3	38.2	6.40	7.40	6.80
First half of 2008	3.4	1.7	5.1	6.22	6.47	6.30
Second half of 2008	3.4	1.7	5.1	6.22	6.47	6.30
12 months of 2008	6.8	3.4	10.2	$6.22	$6.47	$6.30
	Oil (in Mbbl)			Average price per bbl, net to the well
Fourth quarter 2005	303	110	413	$41.60	$40.36	$41.27
First half of 2006	561	163	724	49.42	61.42	52.12
Second half of 2006	570	166	736	49.42	61.42	52.12
12 months of 2006	1,131	329	1,460	49.42	61.42	52.12
First half of 2007	217	145	362	57.48	57.86	57.63
Second half of 2007	221	147	368	57.48	57.86	57.63
12 months of 2007	438	292	730	$57.48	$57.86	$57.63

Market Resources held gas-price hedging contracts covering the price exposure for about 182.3 million MMBtu of gas, 2.6 MMbbl of oil and 14.1 million gallons of NGL as of September 30, 2005. A year earlier Market Resources’ hedging contracts covered 148.3 million MMBtu of natural gas and 1.5 MMbbl of oil.

The following table summarizes changes in the fair value of hedging contracts from December 31, 2004 to September 30, 2005:

	(in thousands)
Net fair value of gas- and oil-hedging contracts outstanding at December 31, 2004	($  67,501)
Contracts realized or otherwise settled	34,977
Increase in gas and oil prices on futures markets	(276,710)
Contracts added since December 31, 2004	(258,861)
Net fair value of gas- and oil-hedging contracts outstanding at September 30, 2005	($568,095)

A table of the net fair value of gas-hedging contracts as of September 30, 2005, is shown below. About 74% 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, 2006	($420,550)
Contracts maturing between October 1, 2006 and September 30, 2007	(123,222)
Contracts maturing between October 1, 2007 and September 30, 2008	(22,252)
Contracts maturing after October 1, 2008	(2,071)
Net fair value of gas- and oil-hedging contracts at September 30, 2005	($568,095)

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,
	2005	2004
	(in millions)
Mark-to-market valuation – liability	($568.1)	($165.3)
Value if market prices of gas and oil decline by 10%	(403.6)	(91.4)
Value if market prices of gas and oil increase by 10%	($732.6)	(239.2)

Interest-Rate Risk Management

As of September 30, 2005, Market Resources had $350.0 million of fixed-rate long-term debt and $200.0 million of variable-rate long-term debt.

ITEM 4.  CONTROLS AND PROCEDURES.

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-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by the 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. The Company’s Chief Executive Officer and Chief Financial Officer also concluded that the controls and procedures were effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management including its principal executive and financial officers or persons performing similar functions as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls.

Since the Evaluation Date, there have not been any changes in the Company’s internal controls or other factors during the most recent fiscal quarter that could materially affect such controls.

PART II.  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS.

On January 25, 2005, the Department of Environmental Quality (DEQ) for the state of Oklahoma issued a seven-count Notice of Violation (NOV) to Gas Management in conjunction with the operation of the Beaver processing plant in western Oklahoma. The DEQ alleges that Gas Management violated federal and state environmental laws and regulations concerning air emissions when operating the facility and when reporting about such operations. As requested by DEQ, Gas Management filed a compliance plan on March 1, 2005. Gas Management has entered into a Consent Order with DEQ dated October 13 2005 for the payment of $114,450 to resolve the outstanding NOV.

ITEM 6. EXHIBITS

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

Exhibit No.

Exhibit

      4.4.

Second Amendment to Credit Agreement dated August 9, 2005 by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders.

      4.5.

Third Amendment to Credit Agreement dated September 20, 2005 by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders.

     31.1.

Certification signed by Charles B. Stanley, Questar Market Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

     31.2.

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

     32.

Certification signed by Charles B. Stanley and S. E. Parks, Questar Market Resources, Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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 10, 2005

/s/Charles B. Stanley

         Date

Charles B. Stanley

President and Chief Executive Officer

November 10, 2005

/s/S. E. Parks

         Date

S. E. Parks, Vice President and

Chief Financial Officer

Exhibits List

Exhibits

      4.4.

Second Amendment to Credit Agreement dated August 9, 2005 by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders.

      4.5.

Third Amendment to Credit Agreement dated September 20, 2005 by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders.

     31.1.

Certification signed by Charles B. Stanley, Questar Market Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

     31.2.

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

     32.

Certification signed by Charles B. Stanley and S. E. Parks, Questar Market Resources Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

#

Exhibit 4.4.

SECOND AMENDMENT TO CREDIT AGREEMENT

THIS SECOND AMENDMENT TO CREDIT AGREEMENT (herein called the “Amendment”) made as of August 9, 2005 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, as amended by that certain First Amendment as defined below, the “Original Agreement”), for the purpose and consideration therein expressed, whereby Lenders became obligated to make loans to Borrower as therein provided;

WHEREAS, Borrower, Administrative Agent and Lenders entered into that certain First Amendment to Credit Agreement dated as of October 25, 2004 (the “First Amendment”), for the purpose and consideration therein expressed; and

WHEREAS, Borrower, Administrative Agent and Lenders desire to further 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 Second Amendment to Credit Agreement.

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

ARTICLE II.

AMENDMENT TO ORIGINAL AGREEMENT

Section 2.1.

Defined Terms.  The following definitions in Section 1.01 of the Original Agreement are hereby amended in their entirety to read as follows:

“Applicable Rate” means, from time to time, the following percentages per annum, based upon the Debt Rating as set forth below:

Applicable Rate
Pricing Level	Debt Ratings S&P/Moody’s	Commitment Fee	Eurodollar Rate Letters of Credit Fee	Utilization Fee
1	≥A-/A3	0.080%	0.300%	0.100%
2	BBB+/Baa1	0.100%	0.350%	0.100%
3	BBB/Baa2	0.125%	0.450%	0.100%
4	BBB-/Baa3	0.150%	0.550%	0.150%
5	≤BB+/Ba1	0.170%	0.750%	0.250%

“Maturity Date” means August 9, 2010.

Section 2.2.

Extension of Maturity Date.  The following new Section 2.14 is hereby added to the Original Agreement, immediately following Section 2.13 of the Original Agreement, to read as follows:

“Section 2.14.  Extension of Maturity Date.

(a)

Not earlier than 60 days prior to, nor later than 45 days prior to August 9, 2006 and August 9 2007, the Borrower may, upon notice to the Administrative Agent (which shall promptly notify the Lenders), request a one-year extension of the Maturity Date then in effect.  Within 30 days of delivery of such notice, each Lender shall notify the Administrative Agent whether or not it consents to such extension (which consent may be given or withheld in such Lender’s sole and absolute discretion).  Any Lender not responding within the above time period shall be deemed not to have consented to such extension.  The Administrative Agent shall promptly notify the Borrower and the Lenders of the Lenders’ responses.  

(b)

The Maturity Date shall be extended only if Lenders holding at least 50% of the Aggregate Commitments (calculated excluding Defaulting Lenders and prior to giving effect to any replacements of Lenders permitted herein) (the “Consenting Lenders”) have consented thereto.  If so extended, the Maturity Date, as to the Consenting Lenders, shall be extended to the date which is one year after the Maturity Date then in effect, effective as of the date the Administrative Agent notifies the Consenting Lenders that the conditions of this Section 2.14 have been satisfied (the “Extension Effective Date”).  The Administrative Agent and the Borrower shall promptly confirm to the Lenders such extension and the Extension Effective Date.  

(c)

Notwithstanding the foregoing, the extension of the Maturity Date pursuant to this Section shall not be effective with respect to any Lender unless:

(i)

no Default or Event of Default shall have occurred and be continuing on the date of such extension and no Default or Event of Default shall occur as a result of such extension;

(ii)

the representations and warranties contained in this Agreement are true and correct on and as of the date of such extension and after the extension is effective, as though made on and as of such date (or, if any such representation or warranty is expressly stated to have been made as of a specific date, as of such specific date);

(iii)

 the Borrower shall pay any Loans outstanding on the Maturity Date as to any non-extending Lenders (and pay any additional amounts required pursuant to Section 3.05) to the extent necessary to keep outstanding Loans ratable with any revised and new Pro Rata Shares of all the Lenders effective as of the Extension Effective Date;

(iv)

the Borrower shall deliver to the Administrative Agent a certificate signed by a Responsible Officer of the Borrower (A) certifying and attaching the resolutions adopted by such Loan Party authorizing such extension and (B) certifying that, (1) before and after giving effect to such extension, the representations and warranties contained in  Article V and the other Loan Documents made by it are true and correct in all material respects on and as of the Extension Effective Date, except to the extent that such representations and warranties specifically refer to an earlier date, (2) before and after giving effect to such extension no Default exists or will exist, and (3) no event has occurred since the date of the most recent audited financial statements of the Borrower delivered pursuant to Section 6.02(a) and (b) that has had, or could reasonably be expected to have, a Material Adverse Effect; and

(v)

the Borrower shall deliver to Administrative Agent an opinion addressing such matters relating to such extension as Administrative Agent may reasonably request.

(d)

If any Lender does not consent to the extension of the Maturity Date as provided in this Section 2.14, the Borrower shall have the right to replace such Lender in accordance with Section 10.16.

(e)

This Section shall supersede any provisions in Section 2.06 or 10.01 to the contrary.”

Section 2.3

Fees.

Clause (b) of Section 2.08 of the Original Agreement is hereby amended in its entirety to read as follows:

(b)

Utilization Fee.  The Borrower shall pay to the Administrative Agent for the account of each Lender in accordance with its Pro Rata Share, a utilization fee equal to the Applicable Rate times the Total Outstandings on each day that the Total Outstandings exceed 50% of the actual daily amount of the Aggregate Commitments then in effect (or, if terminated, in effect immediately prior to such termination).  The utilization fee shall be due and payable quarterly in arrears on the last Business Day of each March, June, September and December, commencing with the first such date to occur after the Closing Date, and on the Maturity Date.  The utilization fee shall be calculated quarterly in arrears and if there is any change in the Applicable Rate during any quarter, the daily amount shall be computed and multiplied by the Applicable Rate for each period during which such Applicable Rate was in effect.  The utilization fee shall accrue at all times, including at any time during which one or more of the conditions in Article IV is not met.”

Section 2.4.

Conditions to all Credit Extensions.  Section 4.02 (a) of the Original Agreement is hereby amended in its entirety to read as follows:

“(a)

The representations and warranties of the Borrower contained in Article V or any other Loan Document, or which are contained in any document furnished at any time under or in connection herewith or therewith (excluding the representation and warranty set forth in Section 5.06(c) of this Agreement), shall be true and correct on and as of the date of such Credit Extension, except to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct as of such earlier date, and except that for purposes of this Section 4.02 (a) the representations and warranties contained in subsections (a) and (b) of Section 5.06 shall be deemed to refer to the most recent statements furnished pursuant to clauses (a) and (b), respectively, of Section 6.02.”

Section 2.5

Consolidated Interest Coverage Ratio.   Section 7.12 of the Original Agreement is hereby deleted from the Original Agreement.

ARTICLE III.

CONDITIONS TO 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;

(iii)

an opinion of counsel with respect to the due authorization, execution and delivery, and enforceability of this Amendment by and against the Borrower in a form acceptable to Administrative Agent; and

(iv)

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 and reimbursements required 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, 2004 and the unaudited quarterly consolidated financial statements of Borrower dated as of March 31, 2005 fairly present the consolidated financial position at such dates and the consolidated results of operations and the changes in consolidated financial position for the periods ending on such dates for Borrower.  Copies of such consolidated 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.  IN WITNESS WHEREOF, this Amendment is executed as of the date first above written.

QUESTAR MARKET RESOURCES, INC.

/s/Charles B. Stanley

Charles B. Stanley
President and Chief Executive Officer

BANK OF AMERICA, N.A.,

 as Administrative Agent

/s/Zewditu Menelik

Zewditu Menelik
Vice President

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

/s/Zewditu Menelik

Zewditu Menelik
Vice President

HARRIS NESBITT FINANCING, INC., as a Lender

/s/Cahal B. Carmody

Cahal B. Carmody
Vice President

WELLS FARGO BANK, NA,

as Co-Syndication Agent and a Lender

/s/Troy S. Akagi

Troy S. Akagi
Vice President

SUNTRUST BANK, as

Co-Documentation Agent and a Lender

/s/Kelley Brunson

Kelley Brunson

Vice President

JP MORGAN CHASE BANK, N.A., as Co-Documentation Agent and a Lender

/s/Robert C. Mertensotto

Robert C. Mertensotto
Managing Director

WACHOVIA BANK, NATIONAL ASSOCIATION, as a Lender

/s/Philip Trinder

Philip Trinder

Vice President

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

/s/Kelton Glasscock

Kelton Glasscock
Vice President & Manager

/s/Jay Fort

Jay Fort

Vice President

BARCLAYS BANK PLC,  as a Lender

/s/Nicholas Bell

Nicholas Bell

Director

THE ROYAL BANK OF SCOTLAND plc, as a Lender

/s/Matthew J. Main

Matthew J. Main
Senior Vice President

U.S. BANK NATIONAL ASSOCIATION, as a Lender

/s/Mark E. Thompson

Mark E. Thompson
Vice President

Exhibit 4.5.

THIRD AMENDMENT TO CREDIT AGREEMENT

THIS THIRD AMENDMENT TO CREDIT AGREEMENT (herein called the “Amendment”) made as of September 20, 2005 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, (as amended by that certain First Amendment to Credit Agreement dated as of October 25, 2004 and that certain Second Amendment to Credit Agreement dated as of August 9, 2005, 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 further 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 Third 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 $400,000,000 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 TO EFFECTIVENESS AND POST-CLOSING DOCUMENTS

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 this Amendment executed by Borrower and Required Lenders.

Section 3.2.

Post-Closing Documents.  

(a)

Within ten (10) days after the date hereof, Borrower shall deliver to Administrative Agent:

(i)

a certificate of the Secretary of Borrower dated the date of this Amendment certifying: (x) that resolutions adopted by the Board of Directors of the Borrower authorize the execution, delivery and performance of this Amendment by Borrower; (y) the names and true signatures of the officers of the Borrower authorized to sign this Amendment; and (z) 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;

(ii)

an opinion of counsel with respect to the due authorization, execution and delivery of this Amendment, and the enforceability of the Original Agreement as amended by this Amendment, by and against the Borrower and covering such other matters as may be reasonably requested by Administrative Agent in a form acceptable to Administrative Agent; and

(iii)

such other supporting documents as Administrative Agent may reasonably request.

Within ten (10) days after the date of this Amendment, Borrower shall have paid, in connection with such Loan Documents, fees and reimbursements required 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, 2004 and the unaudited quarterly consolidated financial statements of Borrower dated as of June 30, 2005 fairly present the consolidated financial position at such dates and the consolidated results of operations and the changes in consolidated financial position for the periods ending on such dates for Borrower.  Copies of such consolidated 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.

/s/Charles B. Stanley

Charles B. Stanley
President and Chief Executive Officer

BANK OF AMERICA, N.A., as Administrative Agent

/s/Sheri Starbuck

Sheri Starbuck
Vice President

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

/s/Joseph F. Scott

Joseph F. Scott
Vice President

HARRIS NESBITT FINANCING, INC., as a Lender

/s/Cahal B. Carmody

Cahal Carmody
Vice President

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

/s/Troy S. Akagi

Troy Akagi
Vice President

SUNTRUST BANK, as
Co-Documentation Agent and a Lender

/s/Joseph M. McCreery

Joseph M. McCreery
Vice President

JP MORGAN CHASE BANK, N.A., as Co-Documentation Agent and a Lender

/s/Robert W. Traband

Robert W. Traband
Vice President

WACHOVIA BANK, NATIONAL ASSOCIATION, as a Lender

/s/Philip Trinder

Philip Trinder
Vice President

BARCLAYS BANK PLC, as a Lender

/s/Nicholas A. Bell

Nicholas A. Bell

Director

THE ROYAL BANK OF SCOTLAND plc, as a Lender

/s/Keith Johnson

Keith Johnson

Senior Vice President

U.S. BANK NATIONAL ASSOCIATION, as a Lender

/s/Mark E. Thompson

Mark E. Thompson

Vice President

Exhibit 31.1.

CERTIFICATION

I, Charles B. Stanley, certify that:

1.

I have reviewed this quarterly report of Questar Market Resources, Inc. on Form 10-Q for the period ending September 30, 2005;

2.

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

3.

Based on my knowledge, the financial statements, and other financial information included in this 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 report;

4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared;

b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 10, 2005

/s/Charles B. Stanley

        Date

Charles B. Stanley

President and Chief

Executive Officer

Exhibit 31.2.

CERTIFICATION

I, S. E. Parks, certify that:

1.

I have reviewed this quarterly report of Questar Market Resources, Inc. on Form 10-Q for the period ending September 30, 2005;

2.

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

3.

Based on my knowledge, the financial statements, and other financial information included in this 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 report;

4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared;

b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 10, 2005

/s/S. E. Parks

       Date

S. E. Parks

Vice President

and Chief Financial Officer

Exhibit No. 32.

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Questar Market Resources, Inc. (the Company) on Form 10-Q for the period ending September 30, 2005, as filed with the Securities and Exchange Commission on the date hereof (the Report), Charles B. Stanley, President and Chief Executive Officer of the Company, and S. E. Parks, Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1)

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

(2)

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

QUESTAR MARKET RESOURCES, INC.

November 10, 2005

/s/Charles B. Stanley

          Date

Charles B. Stanley

President and Chief Executive Officer

November 10, 2005

/s/S. E. Parks

          Date

S. E. Parks

Vice President and Chief Financial Officer