Edgar Filing: QUESTAR CORP

UNITED STATES

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended June 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 1-8796

QUESTAR CORPORATION
(Exact name of registrant as specified in charter)

STATE OF UTAH 87-0407509

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

incorporation or organization) Identification No.)

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

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

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 and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class

Outstanding as of July 31, 2005

Common Stock, without Par

85,039,048 Shares

value with attached Common

Stock Purchase Rights

Questar Corporation

Form 10-Q for the Quarterly Period Ended June 30, 2005

TABLE OF CONTENTS

Page #

NATURE OF BUSINESS

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

GLOSSARY OF COMMONLY USED TERMS

SEC FILINGS AND WEBSITE INFORMATION

PART I.

FINANCIAL INFORMATION

Item 1.

Financial Statements

Consolidated Statements of Income for the three and six months ended

June 30, 2005 and 2004

Condensed Consolidated Balance Sheets at June 30, 2005

and December 31, 2004

Condensed Consolidated Statements of Cash Flows for the six months ended

June 30, 2005 and 2004

Notes Accompanying the Consolidated Financial Statements

Item 2.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

Item 4.

Controls and Procedures

Unregistered Sales of Equity Securities and Use of Proceeds

Item 4.

Submission of Matters to a Vote of Security Holders

NATURE OF BUSINESS

Questar Corporation (Questar or the Company), is a natural gas-focused energy company with three principal lines of business – gas and oil exploration and production, interstate gas transportation, and retail-gas distribution. Questar Market Resources (Market Resources) subsidiaries engage in gas and oil exploration, development and production, gas gathering and processing, wholesale gas and oil marketing, and gas storage. Questar Pipeline Company (Questar Pipeline) provides interstate natural gas transportation and storage services. Questar Gas Company (Questar Gas) provides retail natural gas distribution.

Questar is a holding company, as that term is defined in the Public Utility Holding Company Act of 1935, because Questar Gas is a natural gas utility. Questar, however, qualifies for and claims an exemption from provisions of the act applicable to registered holding companies. Questar conducts most of its operations through subsidiaries. The parent-holding company performs certain management, legal, tax, administrative and other services for its subsidiaries.

Questar operates in the Rocky Mountain and Midcontinent regions of the United States of America and is headquartered in Salt Lake City, Utah. Shares of Questar common stock trade on the New York Stock Exchange under the symbol STR.

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 Questar ’s expected performance at the time, actual results may vary from management’s stated expectations and projections due to a variety of factors.

Important assumptions and other significant factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements include, but are not limited to, the following:

Questar subsidiaries find, produce and sell natural gas, oil and natural gas liquids (NGL)

Natural gas, oil and NGL prices are volatile and, therefore, Questar revenues, cash flow and earnings can be volatile. The Company cannot predict future natural gas, oil and NGL prices, 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 price and availability of drilling rigs and other materials and services.

The Company uses financial contracts to hedge its exposure to volatile energy 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 rising prices. Questar believes the Company’s regulated businesses – interstate natural gas transportation and retail gas distribution – and its Wexpro subsidiary generate revenues that are not significantly sensitive to short-term fluctuations in energy prices.

Questar’s profitability depends not only on prevailing prices for natural gas and oil, 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 Exploration and Production’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.

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

Questar 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.

Questar 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 and oil 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, as long as they do not supersede or conflict with federal law. 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 Questar’s 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.

Questar Pipeline’s natural gas-transportation and storage operations are regulated by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The FERC has authority to: set rates for natural gas transportation, storage and related services; set rules governing business relationships between the pipeline subsidiary and its affiliates; approve new pipeline and storage-facility construction; and establish policies and procedures for accounting, purchase, sale, abandonment and other activities. FERC policies may adversely affect Questar Pipeline profitability. The FERC also has various affiliate rules that may cause the Company to incur additional costs of compliance.

Both Questar Pipeline and Questar Gas incur significant costs to comply with federal pipeline-safety regulations . Questar may also be affected by possible future regulations requiring the tracking, reporting and reduction of greenhouse-gas emissions.

State agencies regulate the distribution of natural gas

Questar Gas’s natural gas-distribution business is regulated by the Public Service Commission of Utah (PSCU) and the Public Service Commission of Wyoming (PSCW). These commissions set rates for distribution services and establish policies and procedures for services, accounting, purchase, sale and other activities. PSCU and PSCW policies may adversely affect Questar Gas profitability.

Other factors may affect Questar’s results

Other factors may affect Questar’s 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, other pipelines and storage facilities; effects of accounting policies issued periodically by accounting standard-setting bodies; terrorist attacks or acts of war; changes in the business or financial condition of the Company; changes in credit ratings; and availability of financing for Questar and its subsidiaries.

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. Questar 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.

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 14.73 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.

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.

heating-degree days

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

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. 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.

Mdth

One thousand decatherms.

Mdthe

One thousand decatherm 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.

MMbbl

One million barrels.

MMBtu

One million British thermal units.

MMcf

One million cubic feet.

MMcfe

One million cubic feet of natural gas equivalents.

MMdth

One million decatherms.

MMgal

One million U. S. gallons.

natural gas liquids

Liquid hydrocarbons that are extracted and separated from the natural gas

(NGL)

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

net

Net gas and oil wells or net acres are determined by 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

replacement ratio

reserves 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

reserves

and proved-developed 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

producing reserves

existing wells.

proved-undeveloped

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

reserves

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

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

Questar, Market Resources, Questar Pipeline and Questar Gas file annual, quarterly, and current reports with the Securities and Exchange Commission (SEC). Questar also regularly files proxy statements and other documents with the SEC. Investors 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 Questar at Questar ’s website at www.questar.com. Questar’s website contains Statements of Responsibility for Board Committees, Corporate Governance Guidelines and its Business Ethics Policy.

Questar and each of its reporting subsidiaries make available, free of charge, through the 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 and all reports filed by executive officers and directors under Section 16 of the Exchange Act reporting transactions in Questar securities. Access to these reports is provided as soon as reasonably practicable after such reports are electronically filed with the SEC.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QUESTAR CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
	(in thousands, except per share amounts)
REVENUES
Market Resources	$344,896	$244,360	$659,234	$478,414
Questar Pipeline	19,087	17,869	36,999	35,882
Questar Gas	151,043	102,235	494,733	409,114
Corporate and other operations	5,183	5,051	9,567	9,721

TOTAL REVENUES	520,209	369,515	1,200,533	933,131

OPERATING EXPENSES
Cost of natural gas and other products sold	234,127	127,727	576,913	393,986
Operating and maintenance	84,409	76,417	170,258	154,846
Depreciation, depletion and amortization	59,807	55,408	118,632	107,677
Questar Gas rate-refund obligation		1,505		2,995
Exploration	5,476	1,266	6,849	2,353
Abandonment and impairment of gas,
oil and other properties	1,493	2,287	2,898	6,693
Production and other taxes	26,250	22,608	52,635	45,494

TOTAL OPERATING EXPENSES	411,562	287,218	928,185	714,044

OPERATING INCOME	108,647	82,297	272,348	219,087

Interest and other income	2,922	1,336	5,573	3,160
Earnings from unconsolidated affiliates	1,675	1,264	3,221	2,574
Minority interest				(270)
Debt expense	(16,643)	(17,055)	(33,365)	(34,571)

INCOME BEFORE INCOME TAXES	96,601	67,842	247,777	189,980
Income taxes	35,874	25,286	91,879	71,291

NET INCOME	$ 60,727	$ 42,556	$155,898	$118,689

EARNINGS PER COMMON SHARE
Basic	$ 0.71	$ 0.51	$ 1.84	$ 1.42
Diluted	0.70	0.50	1.79	1.39

Weighted average common shares outstanding
Used in basic calculation	84,679	83,651	84,546	83,511
Used in diluted calculation	87,051	85,445	86,888	85,305

Dividends per common share	$ 0.225	$ 0.215	$ 0.44	$ 0.42

See notes accompanying the consolidated financial statements

QUESTAR CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,	December 31,
	2005	2004
	(Unaudited)
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$ 657	$ 3,681
Accounts receivable, net	202,534	262,373
Unbilled gas accounts receivable	9,024	59,160
Hedging collateral deposits	62,600
Fair value of hedging contracts	199	9,334
Inventories, at lower of average cost or market
Gas and oil storage	36,025	66,944
Materials and supplies	31,977	18,993
Prepaid expenses and other	19,897	23,690
Purchased-gas adjustments	14,642	35,853
Deferred income taxes – current	47,842	6,968
Total current assets	425,397	486,996
Property, plant and equipment	5,104,115	4,877,771
Less accumulated depreciation, depletion and amortization	1,985,816	1,893,111
Net property, plant and equipment	3,118,299	2,984,660
Investment in unconsolidated affiliates	36,075	33,229
Goodwill	71,260	71,260
Regulatory assets	30,113	32,120
Intangible pension asset	12,394	12,394
Fair value of hedging contracts		1,815
Other noncurrent assets , net	25,017	31,152
	$3,718,555	$3,653,626

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt	$ 37,000	$ 68,000
Accounts payable and accrued expenses	283,362	348,264
Questar Gas customer-credit balances	12,223	24,771
Rate-refund obligations	8,723	25,343
Fair value of hedging contracts	141,542	64,179
Total current liabilities	482,850	530,557
Long-term debt, less current portion	933,199	933,195
Deferred income taxes	558,600	553,401
Asset-retirement obligations	70,164	67,288
Pension liability and post-retirement benefits	49,259	47,919
Fair value of hedging contracts	74,304	14,471
Other long-term liabilities	68,927	67,237

Common shareholders' equity
Common stock	372,690	358,017
Retained earnings	1,254,327	1,135,718
Accumulated other comprehensive loss	(145,765)	(54,177)
Total common shareholders' equity	1,481,252	1,439,558
	$3,718,555	$3,653,626

See notes accompanying the consolidated financial statements

QUESTAR CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	6 Months Ended
	June 30,
	2005	2004
	(in thousands)

OPERATING ACTIVITIES
Net income	$ 155,898	$ 118,689
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	121,510	112,566
Deferred income taxes	20,555	35,093
Amortization of nonvested shares	2,026	1,128
Abandonment and impairment of gas, oil and other properties	2,898	6,693
Earnings from unconsolidated affiliates,
net of cash distributions	(1,004)	1,971
Net (gain) loss from asset sales	(3,594)	16
Minority interest and other	328	336
	298,617	276,492
Changes in operating assets and liabilities	27,729	31,070
NET CASH PROVIDED FROM
OPERATING ACTIVITIES	326,346	307,562

INVESTING ACTIVITIES
Capital expenditures
Purchase of property, plant and equipment	(281,278)	(154,118)
Other investments	(1,842)	(1,000)
Total capital expenditures	(283,120)	(155,118)
Proceeds from disposition of assets	16,380	1,562
NET CASH USED IN INVESTING ACTIVITIES	(266,740)	(153,556)

FINANCING ACTIVITIES
Common stock issued	10,946	14,311
Common stock repurchased	(5,282)	(2,486)
Long-term debt repaid	(5)	(71,996)
Decrease in short-term debt	(31,000)	(73,000)
Checks in excess of cash balances		740
Dividends paid	(37,289)	(35,163)
Other		(317)
NET CASH USED IN FINANCING ACTIVITIES	(62,630)	(167,911)
Change in cash and cash equivalents	(3,024)	(13,905)
Beginning cash and cash equivalents	3,681	13,905
Ending cash and cash equivalents	$ 657	$ -

See notes accompanying the consolidated financial statements

QUESTAR CORPORATION

NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation of Interim Consolidated Financial Statements

The accompanying interim consolidated financial statements 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 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 six months ended June 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 , as amended , for the year ended December 31, 2004.

Note 2 – Rate-Refund Obligations

Gas-Processing Dispute

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

As a result of the court’s order, Questar Gas recorded a liability for a potential refund to gas-distribution customers. A total liability of $29.0 million include d revenue received for processing costs and interest from June 1999 through September 2004.

On August 30, 2004, the PSCU ruled that Questar Gas failed in 1999 to prove that its decision to contract for gas processing with an affiliate was prudent. The PSCU rejected the stipulation, denied the request for rate recovery and ordered the refund of gas-processing costs previously collected in rates. Because Questar Gas had previously accrued a liability for the refund, the order did not have a material impact on 2004 earnings. Questar Gas reduced its rates on September 1, 2004, to eliminate the collection of gas-processing costs and on October 1 began refunding previously collected costs, plus interest, over a 12-month period. As of June 30, 2005, Questar Gas had a refund liability of $3.3 million.

In response to a Questar Gas petition, the PSCU clarified that its order did not preclude recovery of ongoing and certain past-processing costs. Ongoing processing costs are approximately $6.0 million per year. Questar Gas has requested ongoing rate coverage for gas-processing costs in its pass-through filings, but is not currently collecting these costs in rates. The PSCU has conducted several technical conferences to determine what actions should be taken to manage the heat content of the gas supply. On January 31, 2005, Questar Gas filed a rate request with the PSCU to recover $5.7 million per year of gas-processing costs through its gas-balance account. The $5.7 million is Utah’s share of the estimated $6 million cost of operating the gas-processing plant. The Wyoming share has been recovered in rates. Questar Gas filed expert testimony supporting the rate request on April 15, 2005, and hearings before the PSCU are scheduled for fourth quarter 2005.

Fuel-Gas Reimbursement Percentage (FGRP)

During the fourth quarter of 2004, the FERC issued an order to Questar Pipeline in a case involving the annual FGRP. The FERC previously granted Questar Pipeline’s request to increase the FGRP effective January 1, 2004. In its order, the FERC approved the FGRP but also ruled that Questar Pipeline is required to credit to transportation customers proceeds from the sale of natural gas liquids recovered from its hydrocarbon dew point facilities at the Kastler plant in northeastern Utah. Questar Pipeline has accrued a potential liability equal to any liquid revenues from the dew point plant. As of June 30, 2005, Questar Pipeline had reduced revenues by $5.4 million as a credit to customers, including $0.7 million recorded in the first half of 2005.

Questar Pipeline made an annual FGRP filing with the FERC on November 30, 2004, requesting an increase in the FGRP to 2.6%. On December 30, 2004, the FERC approved the request on an interim basis subject to refund and final resolution of the 2004 FGRP proceeding. Several shippers have filed comments with the FERC protesting the FGRP level.

On June 17, 2005, Questar Pipeline filed an uncontested offer of settlement with the FERC to resolve the outstanding issues in the 2004 and 2005 FGRP filings. This settlement, which was negotiated with customers, contains the following terms: (a) The settlement will cover the period from June 1, 2005 through December 31, 2007. (b) No adjustments will be made to FGRP amounts collected by Questar Pipeline prior to June 2005. (c) One-half of the Kastler plant liquid revenues from August 2001 through December 2007 will be refunded to customers and the remaining revenues will be retained by Questar Pipeline. (d) Questar Pipeline will reduce the FGRP amount collected from customers from 2.6% to 2.1% effective June 1, 2005. This percentage consists of 1.95% of ongoing FGRP related costs and 0.15% of prior-period amortization of costs. If actual ongoing costs are less than the 1.95%, the difference will be shared equally with customers beginning January 2006. The FERC approved the settlement on July 26, 2005. Questar Pipeline will record the impact of the settlement in third quarter 2005 results.

Note 3– Asset-Retirement Obligations (ARO)

Questar 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. ARO are adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate.

Changes in asset-retirement obligations were as follows:

	2005	2004
	(in thousands)

Balance at January 1,	$67,288	$61,358
Accretion	2,061	949
Additions	1,326	869
Revisions		695
Retirements and properties sold	(511)	(262)
Balance at June 30,	$70,164	$63,609

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 PSCW. 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 June 30, 2005, approximately $3.4 million was held in this trust invested in a short-term bond index fund.

Note 4 – Earnings Per Share (EPS)

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

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
		(in thousands)

Weighted-average basic common shares outstanding	84,679	83,651	84,546	83,511
Potential number of shares issuable from exercising
stock options and from nonvested restricted shares	2,372	1,794	2,342	1,794
Weighted-average diluted common shares outstanding	87,051	85,445	86,888	85,305

In the first half of 2005, Questar issued 581,000 shares under the terms of the Long-Term Stock Incentive Plan and to satisfy its contributions to the Employee Investment Plan.

Note 5 – Stock-Based Compensation

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

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
		(in thousands)

Net income, as reported	$60,727	$42,556	$155,898	$118,689
Deduct stock-based compensation expense under fair-value based methods	(360)	(652)	(719)	(1,304)
Pro forma net income	$60,367	$41,904	$155,179	$117,385

Earnings per share
Basic, as reported	$ 0.71	$ 0.51	$ 1.84	$ 1.42
Basic, pro forma	0.71	0.50	1.84	1.41
Diluted, as reported	0.70	0.50	1.79	1.39
Diluted, pro forma	0.69	0.49	1.79	1.38

Net income, as reported in the table above, reflects expenses related to restricted stock awards. Restricted shares are valued at the market price on the grant date and amortized over the vesting period. Expense for the six months ended June 30, 2005 and 2004, amounted to $2.0 million and $1.1 million, respectively.

In December 2004 the Financial Accounting Standards Board (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 Company’s effective date for implementation of SFAS 123R is January 1, 2006. Alternative phase-in methods are allowed under SFAS 123R. The Company currently anticipates using the modified prospective phase-in method that requires entities to recognize 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. We believe that none of the alternative phase-in methods would have a material effect on the Company’s operating results or financial position.

Note 6 – Operations by Line of Business

Questar has three primary reporting segments: Market Resources, Questar Pipeline and Questar Gas. Lines of business information are presented according to senior management’s basis for evaluating performance including differences in the nature of products, services and regulation. Certain intersegment sales include intercompany profits. Financial information for reportable segments follows below:

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
		(in thousands)

REVENUES FROM UNAFFILIATED CUSTOMERS
Market Resources	$344,896	$244,360	$ 659,234	$478,414
Questar Pipeline	19,087	17,869	36,999	35,882
Questar Gas	151,043	102,235	494,733	409,114
Corporate and other operations	5,183	5,051	9,567	9,721
	$520,209	$369,515	$1,200,533	$933,131

REVENUES FROM AFFILIATED COMPANIES
Market Resources	$ 35,741	$ 34,090	$ 73,825	$ 68,447
Questar Pipeline	21,517	21,794	43,942	44,087
Questar Gas	1,370	1,017	2,631	2,154
Corporate and other operations	473	5,079	1,075	11,606
	$ 59,101	$ 61,980	$ 121,473	$126,294

OPERATING INCOME (LOSS)
Market Resources	$ 91,063	$ 65,912	$ 185,781	$135,235
Questar Pipeline	17,346	17,051	35,703	35,338
Questar Gas	(2,122)	(2,428)	47,829	45,471
Corporate and other operations	2,360	1,762	3,035	3,043
	$108,647	$ 82,297	$ 272,348	$219,087

NET INCOME (LOSS)
Market Resources	$ 54,761	$ 38,163	$ 111,382	$ 78,418
Questar Pipeline	7,593	7,232	15,932	15,345
Questar Gas	(3,446)	(3,999)	25,266	22,312
Corporate and other operations	1,819	1,160	3,318	2,614
	$ 60,727	$ 42,556	$ 155,898	$118,689

Note 7 – Employee Benefits

Questar has defined-benefit pension and postretirement medical and life insurance plans covering the majority of its employees. Questar complies with minimum-required and maximum-allowed annual contribution levels for its qualified retirement plan as determined by the Employee Retirement Income Security Act and Internal Revenue Code. Subject to these limitations Questar’s objective is to fund the qualified retirement plan in amounts approximately equal to the yearly expense. Currently the qualified pension expense estimate for 2005 is $16.8 million. Components of qualified pension expense included in the determination of interim net income are listed below:

Qualified Pension Expense

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
	(in thousands)

Service cost	$2,103	$1,898	$4,369	$4,039
Interest cost	5,205	4,874	10,340	9,715
Expected return on plan assets	(4,932)	(4,679)	(9,893)	(9,421)
Prior service and other costs	320	481	639	961
Recognized net-actuarial loss	1,019	512	1,754	1,053
Amortization of early-retirement costs	725	719	1,450	1,437
Qualified pension expense	$4,440	$3,805	$8,659	$7,784

Expense of Postretirement Benefits Other than Pensions

The Company currently estimates a $4.4 million expense for postretirement benefits in 2005 before $0.8 million for accretion of a regulatory liability. Expense components are listed below:

	3 Months Ended June 30,		6 Months Ended June 30,
	3 Months Ended June 30,		6 Months Ended June 30,
	2005	2004	2005	2004
		(in thousands)

Service cost	$ 181	$ 172	$ 400	$ 392
Interest cost	990	1,327	2,300	2,644
Expected return on plan assets	(748)	(871)	(1,478)	(1,524)
Special termination benefits		82		82
Amortization of transition obligation	469	470	939	939
Amortization of (gains) losses	(78)	50	41	192
Accretion of regulatory liability	200	200	400	400
Postretirement benefits expense	$1,014	$1,430	$2,602	$3,125

Note 8 – Investment in Unconsolidated Affiliates

Questar uses the equity method to account for investments in unconsolidated affiliates where the Company does not have control. These entities are engaged in gathering and compressing natural gas and have no debt obligations with third-party lenders. The principal affiliates and Questar’s ownership percentage as of June 30, 2005, were Rendezvous Gas Services, LLC, a limited liability corporation, (50%) and Canyon Creek Compression Co., a general partnership (15%).

Operating results representing 100% of these businesses are listed below:

	6 Months Ended June 30,
	6 Months Ended June 30,
	2005	2004
	(in thousands)

Revenues	$9,903	$8,420
Operating income	6,291	5,296
Income before income taxes	6,346	5,306

Note 9 – Comprehensive Income

Comprehensive income is the sum of net income as reported in the Consolidated Statements of Income and other comprehensive income or loss reported in Common Shareholders’ Equity. Other comprehensive income or loss in the first half 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, oil or NGL underlying the derivative instrument is sold. A summary of comprehensive income is shown below:

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
	(in thousands)

Net income	$ 60,727	$ 42,556	$ 155,898	$118,689
Other comprehensive income (loss)
Unrealized gain (loss) on energy- hedging transactions	38,336	(40,829)	(147,818)	(64,589)
Income taxes	(14,541)	15,266	56,230	24,201
Net other comprehensive income (loss)	23,795	(25,563)	(91,588)	(40,388)
Total comprehensive income	$ 84,522	$ 16,993	$ 64,310	$ 78,301

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

	June 30,	December 31,
	2005	2004
	(in thousands)

Unrealized loss on energy-hedging transactions	($133,738)	($42,150)
Additional pension liability	(12,027)	(12,027)
Accumulated other comprehensive loss	($145,765)	($54,177)

Note 10 – Recent Accounting Developments

In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143” (SFAS 143). FIN 47 clarifies the term conditional asset retirement obligation as used in SFAS 143 and requires a liability to be recorded if the fair value of the obligation can be reasonably estimated. The types of asset retirement obligations that are covered by FIN 47 are those for which an entity has a legal obligation to perform an asset retirement activity; however the timing and/or method of settling the obligation are conditional on a future event that may or may not be within the control of the entity. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than fiscal years ending after December 15, 2005. The Company does not expect the guidelines of FIN 47 will have a significant impact on its results of operations or financial position.

In June 2005 the FASB issued SFAS 154, “Accounting Changes and Error Corrections,” a replacement of existing accounting pronouncements. SFAS 154 modifies accounting and reporting requirements when a company voluntarily chooses to change an accounting principle or correct an accounting error. SFAS 154 requires retroactive restatement of prior period financial statements unless it is impractical. Previous accounting guidelines allowed recognition by cumulative effect in the period of the accounting change. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Earlier application is permitted for accounting changes and corrections of errors made occurring in fiscal years beginning after June 1, 2005. SFAS 154 does not change the transition provisions of any existing accounting pronouncements, including those that are in a transition phase as of the effective date of SFAS 154.

In July 2005 the 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 Questar 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.

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

(Unaudited)

SUMMARY

Questar reported net income for the second quarter of 2005 of $60.7 million or $0.70 per diluted share compared to $42.6 million or $0.50 per share for the second quarter of 2004. Questar earned $155.9 million or $1.79 per diluted share in the first half of 2005 compared to $118.7 million or $1.39 per share for the first half of 2004. Following are comparisons of net income by line of business.

	3 Months Ended June 30,		6 Months Ended June 30,
	2005	2004	2005	2004
	(in thousands, except per share amounts)
Net income (loss)
Market Resources	$54,761	$38,163	$111,382	$ 78,418
Questar Pipeline	7,593	7,232	15,932	15,345
Questar Gas	(3,446)	(3,999)	25,266	22,312
Corporate and other operations	1,819	1,160	3,318	2,614
Total	$60,727	$42,556	$155,898	$118,689

Earnings per diluted common share	$0.70	$0.50	$1.79	$1.39

Market Resources net income was 43% higher in the second quarter of 2005 and 42% higher for the first six months of 2005 compared to the same periods of 2004. The increase in net income was driven by higher prices for gas, oil and NGL, increased gas and oil production and increased investment base at Wexpro. In Gas Management, a 94% increase in NGL volumes resulting from the first quarter 2005 acquisition of a gas plant in western Wyoming coupled with higher gathering and processing margins also contributed to the increase in Market Resources 2005 earnings.

Questar Pipeline net income increased 5% in the second quarter of 2005 compared to the 2004 period resulting from increased park and loan services, transportation and gathering services. Questar Pipeline net income increased 4% in the first half of 2005 due to new transportation contracts.

Questar Gas’s seasonal loss decreased 14% in the second quarter comparison. Total margin from gas sales increased due to a 3.4% growth in the number of customers and a 1% increase in temperature-adjusted gas usage per customer. Questar Gas increased net income by 13% in the first half of 2005. Total margin from gas sales rose due to an increase in the number of customers and a 2.4% increase in temperature-adjusted usage per customer

RESULTS OF OPERATIONS

Market Resources

Market Resources operates through four principal subsidiaries. Questar Exploration and Production Company (Questar E&P) explores for, acquires, develops and produces gas and oil. Wexpro Company (Wexpro) develops and produces cost-of-service reserves for an affiliated company, Questar Gas. Questar Gas Management Company (Gas Management) provides gas-gathering and processing services for affiliates and third parties. Questar Energy Trading Company (Energy Trading) markets equity and third-party gas and oil, provides risk-management services and through Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir.

Market Resources Consolidated Results

Market Resources net income for the second quarter of 2005 was $54.8 million compared with $38.2 million for the year earlier period, a 43% increase. Net income for the first half of 2005 totaled $111.4 million versus $78.4 million for the same period in 2004, a 42% increase. Operating income increased $25.2 million, or 38%, in the quarter to quarter comparison, and $50.5 million, or 37%, in the first half comparison due primarily to higher commodity prices and increased natural gas and 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 summary of Market Resources’ financial and operating results for the second quarter and first half of 2005 compared with the same periods of 2004.

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
	(in thousands)
OPERATING INCOME
Revenues
Natural gas sales	$112,918	$ 91,127	$221,519	$179,696
Oil and natural-gas-liquids sales	27,976	20,038	54,924	41,218
Cost-of-service gas operations	32,020	31,552	65,653	60,446
Energy marketing	179,806	117,620	333,441	225,078
Gas gathering, processing and other	27,917	18,113	57,522	40,423
Total revenues	380,637	278,450	733,059	546,861
Operating expenses
Energy purchases	177,246	116,872	327,760	222,017
Operating and maintenance	41,776	36,517	83,824	72,230
Depreciation, depletion and amortization	41,257	37,084	81,116	71,033
Exploration	5,476	1,266	6,849	2,353
Abandonment and impairment of gas, oil and other properties	1,493	2,287	2,898	6,693
Production and other taxes	20,962	17,496	42,206	35,152
Wexpro Agreement – oil-income sharing	1,364	1,016	2,625	2,148
Total operating expenses	289,574	212,538	547,278	411,626
Operating income	$ 91,063	$ 65,912	$185,781	$135,235

OPERATING STATISTICS
Questar E&P production volumes
Natural gas (MMcf)	23,410	21,827	46,249	43,715
Oil and natural gas liquids (Mbbl)	586	559	1,169	1,146
Total production (bcfe)	26.9	25.2	53.3	50.6
Average daily production (MMcfe)	296	277	294	278
Average commodity prices, net to the well
Average realized price (including hedges)
Natural gas (per Mcf)	$ 4.82	$ 4.17	$ 4.79	$ 4.11
Oil and natural gas liquids (per bbl)	$ 40.02	$ 29.55	$ 39.38	$ 29.50
Average sales price (excluding hedges)
Natural gas (per Mcf)	$ 5.74	$ 5.03	$ 5.46	$ 4.87
Oil and natural gas liquids (per bbl)	$ 48.52	$ 35.38	$ 47.06	$ 33.57
Wexpro investment base at June 30, net
of depreciation and deferred income taxes (millions)	$ 188.0	$ 165.3
Natural gas gathering volumes (in thousands of MMBtu)
For unaffiliated customers	33,539	32,164	66,074	66,458
For Questar Gas	11,226	9,149	22,482	18,906
For other affiliated customers	14,416	13,336	30,262	27,894
Total gathering	59,181	54,649	118,818	113,258
Gathering revenue (per MMBtu)	$ 0.25	$ 0.21	$ 0.25	$ 0.21
Natural gas and oil marketing volumes (Mdthe)
For unaffiliated customers	27,784	20,725	57,384	42,580
For affiliated customers	20,658	19,446	42,519	39,796
Total marketing	48,442	40,171	99,903	82,376

Questar E&P

For the second quarter of 2005, Questar E&P net income increased 35% to $34.4 million compared with $25.4 million for the same period in 2004. Net income for the first half of 2005 was $70.7 million versus $50.6 million for the same period in 2004, a 40% 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 26.9 bcfe in the second quarter of 2005, a 7% increase compared to the year-earlier period. Production for the first half of 2005 was 53.3 bcfe versus 50.6 bcfe for the 2004 period, a 5% increase. Current year production was negatively impacted by weather-related completion and workover delays on Uinta Basin and western Midcontinent properties, in addition to 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 half 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 half of 2005. A comparison of energy equivalent production by region is shown in the following table.

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
	(in bcfe)
Rocky Mountains
Pinedale Anticline	6.5	4.9	14.1	11.0
Uinta Basin	6.9	6.1	12.6	12.4
Rockies Legacy	4.1	4.7	8.1	9.1
Subtotal – Rocky Mountains	17.5	15.7	34.8	32.5
Midcontinent	9.4	9.5	18.5	18.1
Total Questar E&P production	26.9	25.2	53.3	50.6

Questar E&P’s first half 2005 production from Pinedale increased 28% to 14.1 bcfe versus 11.0 bcfe in the first half 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.

Uinta Basin production increased 2% to 12.6 bcfe in the first half of 2005 compared to 12.4 bcfe a year ago. During the first quarter of 2005, abnormal weather slowed completion and connection of new wells and routine workovers on existing wells. Weather-related conditions (mud) improved in mid-March, and Questar E&P has since reduced the backlog of well completions and workovers. During the second quarter of 2005 the company completed installation of a separate gathering system for new high-pressure wells, which reduced the impact of high gathering system pressure on production from older wells reported in the first quarter of 2005.

Production from Rockies Legacy properties in the first half of 2005 was 8.1 bcfe compared to 9.1 bcfe during the 2004 period, an 11% decrease. Legacy properties include all of Questar E&P’s Rocky Mountain producing properties except 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 the company’s leases and wells during the winter months and payout of a high-volume well that reduced the company’s working interest.

Midcontinent production was 18.5 bcfe in the first half of 2005 compared to 18.1 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 half of 2005, the weighted average realized natural gas price for Questar E&P (including the effects of hedging) was $4.79 per Mcf compared to $4.11 per Mcf for the same period in 2004, a 17% increase. Realized oil and NGL prices for the first half of 2005 averaged $39.38 per bbl, compared with $29.50 per bbl during the prior year period, a 33% increase. A comparison of average realized prices by region, including hedges, is shown in the following table.

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
Natural gas (per Mcf)
Rocky Mountains	$ 4.67	$ 3.83	$ 4.62	$ 3.89
Midcontinent	5.09	4.71	5.11	4.50
Volume-weighted average	$ 4.82	$ 4.17	$ 4.79	$ 4.11
Oil and NGL (per bbl)
Rocky Mountains	$40.42	$28.41	$39.94	$28.62
Midcontinent	39.18	32.14	38.14	31.51
Volume-weighted average	$40.02	$29.55	$39.38	$29.50

Approximately 83% of Questar E&P’s gas production in the second quarter of 2005 was hedged or pre-sold at an average price of $4.88 per Mcf net to the well (which reflects adjustments for regional basis, gathering and processing costs and gas quality). Hedging reduced potential gas revenues $21.4 million during the current period. For the first half of 2005, approximately 85% of Questar E&P’s gas production was hedged or pre-sold at an average price of $4.93 per Mcf net to the well. Hedging reduced potential gas revenues $31.0 million during the first six months of 2005. For the current quarter, Questar E&P also hedged approximately 71% of its oil production at an average net to the well price of $37.95 per bbl. Hedging reduced potential oil revenues $5.0 million during the quarter. For the first half of 2005, Questar E&P hedged or pre-sold approximately 64% of its oil production at an average net to the well price of $36.50 per bbl. Oil hedges reduced potential revenues $9.0 million during the first half of 2005.

Questar 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 June 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 10% to $2.76 per Mcfe in the second quarter of 2005 versus $2.51 per Mcfe in the second quarter of 2004. For the first half of 2005, pre-income tax cost structure rose 12% to $2.73 per Mcfe compared to $2.44 per Mcfe in the first half of 2004.

Depreciation, depletion and amortization expense rose 15% in the second quarter to $1.16 per Mcfe and 14% to $1.14 per Mcfe for the first half 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 $0.12 per Mcfe increase in lifting costs during the current quarter and first half 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 second quarter of 2005, general and administrative expenses decreased $0.02 per Mcfe, or 6%, to $0.31 per Mcfe. For the first half of 2005, general and administrative expenses increased $0.03 per Mcfe, or 10% to $0.33. 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		6 Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
	(per Mcfe)

Lease-operating expense	$0.58	$0.52	$0.56	$0.50
Production taxes	0.50	0.44	0.49	0.43
Lifting costs	1.08	0.96	1.05	0.93
Depreciation, depletion and amortization	1.16	1.01	1.14	1.00
General and administrative expense	0.31	0.33	0.33	0.30
Allocated-interest expense	0.21	0.21	0.21	0.21
Total	$2.76	$2.51	$2.73	$2.44

Exploration expense increased $3.8 million in the second quarter and $4.1 million in the first half 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 divisions. Abandonment and impairment expense declined $0.8 million for the quarter and $3.8 million for the first half 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 Drilling Activity

As of August 4, 2005, Market Resources (both Questar E&P and Wexpro) operated 119 producing wells on the Pinedale Anticline compared to 76 at the end of the second quarter of 2004, and 104 at year-end 2004. Of the 119 producing wells, Questar E&P has working interests in 104 wells and overriding royalty interests in an additional 14 Wexpro-operated wells. Wexpro has working interests in 52 of the 119 producing wells. Market Resources anticipates drilling and completing about 35 Lance Pool wells (combined Lance and Mesaverde formations) on its Pinedale acreage during 2005.

In late June 2005, the company recommenced drilling operations on the Stewart Point 15-29 exploratory well. The well, targeting Rock Springs and Blair Formation sandstones, is currently drilling below 17,600 feet toward a projected total depth of 19,500 feet. The company anticipates reaching total depth during the third quarter of 2005.

Market Resources filed an application in mid-July 2005 with the Wyoming Oil and Gas Conservation Commission (WOGCC) for 10-acre density drilling on a portion of the company’s Pinedale acreage corresponding to the currently productive field limits. The hearing is scheduled for August 9, 2005. Since July 2004 when the WOGCC approved 20-acre density drilling for the company’s Pinedale acreage, Market Resources has drilled, completed and gathered data on several 10-acre density pilot wells and incorporated this data into a detailed reservoir simulation. Based on these pilot wells, the company now believes a minimum of 10-acre density drilling will be necessary to fully develop its Pinedale leasehold.

Uinta Basin

During the first half of 2005, the company drilled or participated in five horizontal Green River formation oil wells, 32 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. The Flat Rock 9P-36-14-19 well was drilled in late 2004 to a total depth of 12,453 feet and completed in the first quarter of 2005. The well is currently capable of producing approximately 4.0 MMcfe per day from the Entrada, Morrison, Cedar Mountain and Dakota formations. Market Resources is currently acquiring seismic data in the area and intends to drill three additional wells during 2005. The planned drilling program includes the first two test wells under the company’s Exploration and Development Agreement with the Ute Indian Tribe covering 12,557 acres of tribal minerals in the area.

Rockies Legacy

In the Vermillion Basin on the Wyoming-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 140,000 net leasehold acres. As of June 30, 2005, the company had recompleted two older wells, drilled and completed one new well, and was drilling two wells. The Alkali Gulch Unit Well No 1 was completed in June and produced an average of 2.4 MMcf per day from the Baxter, Frontier and Dakota formations during the first 30 days. The Hiawatha Deep Unit Well No. 2, an old well that was recompleted in the Baxter, Frontier and Dakota formations, produced an average of 3.3 MMcf per day during the first twelve days of commingled production. The Canyon Creek 34R well was recompleted in the Baxter, Frontier, and Dakota formations and production from all three formations will be commingled in the third quarter. The company plans extended production tests from recently completed and future wells to determine the economic viability of the play.

Midcontinent

During the second 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 18 new Hartshorne wells in the first half of 2005 and anticipates participating in an additional 20 wells in the second half of the year. In the Elm Grove area, the company drilled or participated in 13 new wells through the first half of 2005, and 15 additional wells are planned in the second half.

Wexpro

For the second quarter of 2005 Wexpro earned $10.5 million, compared with $8.8 million for the same period in 2004, a 19% increase. For the first half of 2005 Wexpro’s net income was $20.7 million, compared with $17.8 million for the same period in 2004, a 16% 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 $188.0 million at June 30, 2005, up $22.7 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 118% to $9.0 million in the second quarter of 2005 from $4.1 million in the 2004 period. Net income for the first half of 2005 was $17.8 million versus $9.5 million for the same period in 2004, an 88% increase. Gross keep-whole processing margins (the difference between the market value of natural gas and the market value of NGL extracted from the gas stream or frac spread) grew 72% from $6.0 million in the first half of 2004 to $10.3 million in 2005. The first quarter 2005 acquisition of a gas plant in western Wyoming drove a 94% increase in extracted NGL volumes in the second quarter and 51% for the first half of 2005 versus the year earlier periods. Gathering volumes increased 5.5 million MMBtu to 118.8 million MMBtu in the first half 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 2005 first half, keep-whole contracts benefited from a 22% increase in NGL sales prices versus the prior-year period. Fee-based contracts benefited from a $0.04 increase in the rate charged per MMBtu processed in the six month comparable periods. Forward sales contracts increased NGL revenues by $0.3 million in 2005.

Pre-tax earnings from Gas Management’s 50% interest in Rendezvous Gas Services, LLC, (Rendezvous) increased to $3.1 million for the first half of 2005 versus $2.6 million for 2004, a 21% 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. These core areas are the Pinedale and Jonah fields in western Wyoming and the Uinta Basin in eastern Utah.

During the first quarter 2005 Gas Management completed a transaction in which the company exchanged its interest in an entity that owns and operates a gas gathering system in western Oklahoma for a gas plant in western Wyoming. The acquired plant, a cryogenic gas processing facility located approximately 13 miles south of Gas Management’s Blacks Fork plant, adds approximately 60 MMcf per day of raw gas processing and NGL extraction capacity at its western Wyoming hub. The plant will be 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. The western Oklahoma gas gathering system did not contribute significantly to Gas Management’s 2004 earnings.

Gas Management has also entered into an agreement with a third party producer to gather, compress and process gas in the Uinta Basin of eastern Utah. Under terms of the fee-based agreement, the company will construct gas compression facilities and expand its existing Red Wash gas plant to process an additional 70 MMcf per day of raw gas. The processed gas and liquids will be redelivered to the producer. Construction of the facilities is progressing on schedule. The new facilities should be in service during the third quarter of 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 second quarter of 2005 was $0.8 million compared to a loss of $0.2 million in 2004. For the first half of 2005, net income was $2.2 million compared to $0.5 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 $5.7 million for the first half of 2005 versus $3.1 million a year ago, an 86% increase. The increase in gross margin was due primarily to a 54% higher unit margin and a 21% increase in volumes over the same period last year.

Questar Pipeline

Questar Pipeline provides FERC-regulated interstate natural gas transportation and storage and non-jurisdictional processing and gathering services. Following is a summary of Questar Pipeline’s financial and operating results for the second quarter and first half of 2005 compared with the same periods of 2004.

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
	(in thousands)
OPERATING INCOME
Revenues
Transportation	$26,668	$26,275	$ 53,254	$ 52,974
Storage	9,254	9,277	18,830	18,976
Carbon dioxide processing	1,685	1,878	3,467	3,721
Liquid revenues and other	2,997	2,233	5,390	4,298
Total revenues	40,604	39,663	80,941	79,969
Operating expenses
Operating and maintenance	14,334	13,964	27,468	27,322
Depreciation and amortization	7,259	6,953	14,513	13,917
Other taxes	1,665	1,695	3,257	3,392
Total operating expenses	23,258	22,612	45,238	44,631
Operating income	$17,346	$17,051	$ 35,703	$ 35,338

OPERATING STATISTICS
Natural gas transportation volumes (in Mdth)
For unaffiliated customers	61,403	55,250	116,995	108,984
For Questar Gas	26,212	22,592	69,951	72,468
For other affiliated customers	6,505	5,208	8,481	9,468
Total transportation	94,120	83,050	195,427	190,920
Transportation revenue (per dth)	$ 0.28	$ 0.32	$ 0.27	$ 0.28
Firm-daily transportation demand at June 30, (Mdth)	1,815	1,643

Questar Pipeline’s net income was $7.6 million in the second quarter of 2005 compared with $7.2 million in the second quarter of 2004. For the first half of 2005, Questar Pipeline’s net income was $15.9 million compared with $15.3 million in the year-earlier period. Revenues increased in the 2005 periods due to new transportation contracts. The earnings increase in the first half of 2005 included $246,000 after-tax gains from the sale of assets and the capitalization of $249,000 of carrying costs on a construction project. Questar Pipeline continued to accrue for the refund of liquids revenue from the Kastler processing plant as required by a November 2004 order from the FERC. See Note 2 to the financial statements for a discussion of the FGRP filings with the FERC.

Revenues

Gas transportation volumes increased in the second quarter of 2005 and first half of 2005 over the period year periods due to new transportation contracts and park and loan services. Following is a summary of major changes in Questar Pipeline’s revenues for the three and six months ended June 30, 2005, compared with the same periods of 2004.

	3 Months Ended June 30, 2005 Compared with 2004	6 Months Ended June 30, 2005 Compared with 2004
	(in thousands)
Transportation
New transportation contracts	$ 933	$1,385
Expiration of transportation contracts	(225)	(407)
Elimination of Gas Research Institute Surcharge	(186)	(478)
Other transportation	(129)	(220)
Storage	(23)	(146)
Carbon dioxide processing	(193)	(254)
Liquid revenues and other
Change in liquid revenues before credit	267	885
Credit of Kastler liquid revenues	(208)	(672)
Park and loan revenue	553	728
Other	152	151
Increase	$ 941	$ 972

Questar Pipeline has expanded its transportation system in response to growing regional natural gas production and transportation demand. Questar Pipeline added new transportation contracts in 2004 and 2005 for deliveries to the Kern River pipeline at Goshen, Utah. In the second quarter of 2005, Questar Pipeline began service to an electric generation facility in central Utah.

Questar Pipeline’s existing transportation system is nearly fully subscribed. As of June 30, 2005, Questar Pipeline had firm-transportation contracts of 1,815 Mdth per day compared with 1,643 Mdth per day as of December 31, 2004, and June 30, 2004. The amounts include 80 Mdth per day capacity on the eastern segment of Southern Trails. The increase was primarily due to a new contract of 190 Mdth per day with an electric generation facility. Questar Pipeline’s firm-transportation contracts had a weighted average remaining life of 11.0 years as of June 30, 2005.

Questar Gas is Questar Pipeline’s largest transportation customer with contracts for 951 Mdth per day, including 50 Mdth per day for winter-peaking service. The majority of Questar Gas’s transportation contract demand extends through mid 2017.

Questar Pipeline’s primary storage facility is Clay Basin in eastern Utah. This facility is 100% subscribed under long-term contracts. In addition to Clay Basin Questar Pipeline also owns and operates three smaller aquifer gas storage facilities. Questar Pipeline’s firm storage contracts had a weighted average remaining life of 8.4 years as of June 30, 2005.

Questar Gas has contracted for 26% of firm-storage capacity at Clay Basin for terms extending from three to 14 years and 100% of the firm-storage capacity at the aquifer facilities for terms extending for 13 years.

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

Expenses

Operating and maintenance expenses increased 3% in the second quarter of 2005 and 1% in the first half of 2005 compared with corresponding 2004 periods. The increases were primarily due to higher labor and labor overhead costs offset by the elimination of the Gas Research Institute customer surcharge. Operating and maintenance expenses per dth transported were $0.141 in the first half of 2005 compared with $0.143 in the first half of 2004.

Depreciation expense increased in the 2005 periods reflecting increased pipeline investment.

Clay Basin Storage

Questar Pipeline continues to investigate a potential discrepancy between the book volumes of cushion gas at Clay Basin and cushion-gas volumes implied by pressure-survey data obtained in recent field tests. The current book volume of the cushion gas is 61.5 bcf with a book value of $99.7 million. Questar Pipeline believes the range of the potential discrepancy is 0 – 5 bcf. Analysis to date has not revealed any leaks or gas migration out of the reservoir. Additional reservoir tests and analysis, including reservoir modeling, have narrowed the potential discrepancy . Testing will continue in the fall and spring. This potential discrepancy has not prevented Questar Pipeline from meeting its obligations to storage customers.

If Questar Pipeline determines that the discrepancy is due to changes in the physical conditions in the storage reservoir, the financial impact may include additional investment in cushion gas to meet service obligations. If the discrepancy is due to lost-and-unaccounted-for-gas related to the aggregate impact of about 30 years of lost-and-unaccounted-for gas, Questar Pipeline would expense the original cost of the portion of cushion gas determined to be lost and could file with the FERC to recover costs from customers. The Company believes that the reasonable possible range of losses due to lost-and-unaccounted-for gas is $0 to $8 million before recovery of costs from customers or income tax effects.

New Long-term Contracts

During first quarter 2004 Questar Pipeline obtained long-term transportation contracts to support a $54 million expansion of its central Utah transportation system. The expansion will add 102 Mdth per day of capacity from the Piceance and Uinta basins to the Kern River pipeline, a power-generation facility and Questar Gas’s distribution system. On January 21, 2005, the FERC approved the expansion. As of June 30, 2005, construction of the expansion was about 70% complete. Questar Pipeline expects to begin service in the fourth quarter 2005.

Questar Pipeline also obtained a long-term contract supporting an $11 million extension from the west end of its Mainline 104 near Goshen, Utah 13 miles to a new power plant near Mona, Utah. Construction on this 190-Mdth-per-day line was completed in December 2004 and service began in April 2005.

Carbon Dioxide Processing Plant

Questar Transportation Services, a subsidiary of Questar Pipeline, owns non-jurisdictional gathering lines and a processing plant near Price, Utah. The plant was built in 1999 to process gas on behalf of Questar Gas. Questar Gas has contracted for 100% of the plant’s firm capacity and pays the cost of service for operating the plant.

Southern Trails

The western segment of the Southern Trails line, which runs from the California-Arizona border to Long Beach, California, is currently not in service except for the first 34 miles. Questar Pipeline’s investment is approximately $51 million. Additional investment would be required to complete the conversion of the pipeline from a liquid pipeline to a natural gas pipeline and make connections to customers. The Los Angeles Department of Water and Power (LADWP) budgeted funds in both the current and next budget years to acquire a gas pipeline to serve a power-generation facility. LADWP issued a request for proposal on October 21, 2004. Questar Pipeline filed a response to the request in November 2004. On February 28, 2005, LADWP notified Questar Pipeline of its intent to pursue the proposal. To date no negotiations have taken place and Questar Pipeline withdrew its proposal effective August 3 to pursue other options. Questar Pipeline performed an impairment test for second quarter 2005 in accordance with the provisions of SFAS 144. Based on the results of the test, Questar Pipeline has concluded that no impairment is required based on current expectations.

Regulation

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

Questar Pipeline is required to comply with the Pipeline Safety Improvement Act of 2002. This act and the rules issued by the Department of Transportation (DOT) require interstate pipelines and local distribution companies to implement a 10-year program of risk analysis, pipeline assessment and remedial repair for transportation pipelines located in high-consequence areas such as densely populated locations. Questar Pipeline’s plan for complying with the act was filed with the DOT during 2004. Questar Pipeline estimates that its annual cost to comply with the act will be approximately $1 million, not including costs of pipeline replacement, if necessary.

See Note 2 to the financial statements for a discussion of the Fuel Gas Reimbursement Percentage filings with the FERC.

Questar Gas

Questar Gas distributes natural gas in Utah, southwestern Wyoming and southeastern Idaho. Following is a summary of Questar Gas’s financial and operating results for the second quarter and first half of 2005 compared with the same periods of 2004.

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
	(in thousands)
OPERATING INCOME
Revenues
Residential and commercial sales	$131,737	$ 84,805	$453,783	$367,859
Industrial sales	8,694	10,751	19,101	27,396
Transportation for industrial customers	1,298	1,575	2,905	3,453
Other	10,684	6,121	21,575	12,560
Total revenues	152,413	103,252	497,364	411,268
Cost of natural gas sold	112,359	65,697	363,956	282,427
Margin	40,054	37,555	133,408	128,841
Operating expenses
Operating and maintenance	28,006	25,043	56,917	53,465
Depreciation and amortization	10,892	10,357	22,198	20,666
Rate-refund obligation		1,505		2,995
Other taxes	3,278	3,078	6,464	6,244
Total operating expenses	42,176	39,983	85,579	83,370
Operating income (loss)	$ (2,122)	$ (2,428)	$ 47,829	$ 45,471

OPERATING STATISTICS
Natural gas volumes (in Mdth)
Residential and commercial sales	16,843	11,633	56,762	53,317
Industrial sales	1,394	2,011	3,097	5,025
Transportation for industrial customers	7,068	8,208	15,723	18,146
Total deliveries	25,305	21,852	75,582	76,488
Natural gas revenue (per dth)
Residential and commercial	$7.82	$7.29	$7.99	$6.90
Industrial sales	6.24	5.35	6.17	5.45
Transportation for industrial customers	$0.18	$0.19	$0.18	$0.19
Heating degree days
colder (warmer) than normal	6%	(16%)	(3%)	6%
Average temperature adjusted usage
per customer (dth)	18.2	17.2	68.1	66.5
Customers at June 30,	798,277	771,695

Questar Gas incurred a seasonal loss of $3.4 million in the second quarter of 2005 compared with a loss of $4.0 million in the second quarter of 2004. For the first half of 2005 Questar Gas earned $25.3 million compared with $22.3 million in the first half of 2004.

Margin Analysis

Questar Gas’s margin (revenues less gas costs) increased $2.5 million in the second quarter of 2005 compared to the second quarter of 2004 and increased $4.6 million in the first half of 2005 compared to the same period of 2004. Following is a summary of major changes in Questar Gas’s margin.

		3 Months Ended June 30, 2005 Compared with 2004	6 Months Ended June 30, 2005 Compared with 2004
	(in thousands)

New customers		$ 919	$ 3,439
Increased usage per customer		1,517	2,427
2004 carbon dioxide processing revenues collected from customers		(1,504)	(2,995)
Interest on past-due receivables		402	887
Other		1,165	809
Increase		$ 2,499	$ 4,567

Residential and commercial sales volumes increased 45% in the second quarter of 2005 over the second quarter of 2004 as a result of colder weather, increased customers and increased usage per customer. Residential and commercial sales volumes increased 6% in the first half of 2005 compared with the first half of 2004 as increased customer and increased usage per customer offset the impact of warmer weather. At June 30, 2005, Questar Gas was serving 798,277 customers, a 3.4% increase over the prior year. Housing construction in Utah remained strong, driven by population growth and continuing low mortgage-interest rates. Usage per customer, adjusted for normal temperatures, was up 6% in the second quarter of 2005 and up 2% in the first half of 2005 compared with 2004. Over the long-term, usage per customer has been decreasing due to more efficient appliances and homes and customer response to higher prices.

Weather, as measured in degree days, was 6% colder than normal in the second quarter of 2005 compared with 16% warmer than normal in the second quarter of 2004. For the first half of 2005, weather was 3% warmer than normal compared with 6% colder than normal in the year-earlier period. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations.

Industrial deliveries declined 17% in the second quarter of 2005 and 19% in the first half of 2005 compared with 2004 primarily driven by lower power-generation requirements in the current period. This did not have a significant impact on the financial results because of lower margin on industrial deliveries.

Expenses

Cost of natural gas sold increased 71% in the second quarter of 2005 and 29% in the first half of 2005 compared with 2004 due to increased gas purchase costs and increased volumes. Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the PSCU and the PSCW. Purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. As of June 30, 2005, Questar Gas had a $14.6 million balance in the purchased-gas adjustment account representing gas costs incurred but not yet recovered from customers.

Operating and maintenance expenses increased 12% in the second quarter of 2005 and 6% in the first half of 2005 compared with 2004. The increases are due to higher labor and labor overhead costs and bad debt costs.

Depreciation expense increased 5% in the second quarter of 2005 and 7% in the first half of 2005 compared with 2004, due to plant additions, including a customer information system that was placed in service in July 2004 and transfers of information technology assets from affiliates.

Rate-refund Obligation

See Note 2 in the Notes Accompanying Consolidated Financial Statements under Item 1. Financial Statements in Part I of this report for a discussion of the regulatory proceedings involving Questar Gas’s processing costs.

Regulation

Questar Gas is subject to the requirements of the Pipeline Safety Improvement Act. Questar Gas estimates that it will cost $4.0 to $5.0 million per year to comply with the act, not including costs of pipeline replacement if necessary. The PSCU has allowed Questar Gas to record a regulatory asset for these incremental operating costs incurred to comply with this act until the next rate case or 2007, whichever is sooner.

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’ pre-tax income increased to $1.6 million in the 2005 quarter versus $1.2 million in 2004 and $3.1 million in the first half of 2005 compared to $2.6 million for the same period last year. Rendezvous gathering volumes increased 49% in the second quarter and 34% in the first half of 2005 compared to the year earlier periods.

Debt expense

Lower debt balances and long-term interest rates resulted in lower debt expense in the second quarter and first half of 2005 compared to those same periods of 2004.

Income taxes

The effective combined federal and state income tax rate for the first half was 37.1% in 2005 and 37.5% in 2004.

Liquidity and Capital Resources

Operating Activities

	6 Months Ended
	June 30,
	2005	2004
	(in thousands)

Net income	$155,898	$118,689
Noncash adjustments to net income	142,719	157,803
Changes in operating assets and liabilities	27,729	31,070
Net cash provided from operating activities	$326,346	$307,562

Net cash provided from operating activities increased 6% in the first half of 2005 compared to the first half of 2004. Changes in operating assets and liabilities provided $27.7 million. Seasonal collections of customer receivables provided $113.3 million, which was partially offset by the use of cash for $62.6 million of hedging collateral deposits that were required in response to higher sales prices for gas and oil.

Investing Activities

A comparison of capital expenditures for the first half of 2005 and 2004 plus the budgeted amount for calendar year 2005 is presented below.

			Budget
	6 Months Ended		12 Months Ended
	June 30,		December 31,
	2005	2004	2005
	(in thousands)

Market Resources	$208,914	$108,117	$400,500
Questar Pipeline	38,268	10,221	101,900
Questar Gas	35,151	35,406	82,700
Corporate and other operations	787	1,374	2,000
Total	$283,120	$155,118	$587,100

Financing Activities

Net cash flow provided from operating activities was more than sufficient to fund net capital expenditures and pay dividends in the first half of 2005. The excess cash flow was used to repay short-term debt. Total debt was 40% of total capital at June 30, 2005.

Net capital expenditures include proceeds of $13.0 million, which approximates book value, from the second quarter 2005 sale of data hosting assets. A $3.2 million pretax gain from the sale was fully reserved pending collection of notes.

Short-term debt at June 30, 2005, was comprised of commercial paper with an average interest rate of 3.3%. The Company had $190 million of short-term lines of credit at June 30, 2005. In addition, Market Resources has a $200 million revolving credit facility with banks with no borrowings outstanding at June 30, 2005.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

Commodity-Price Risk Management

Market Resources bears the risk associated with commodity-price changes and uses gas- and oil-price-hedging arrangements in the normal course of business to limit the risk of adverse price movements. However these same arrangements typically limit future gains from favorable price movements. 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 June 30, 2005, approximately 41.3 bcf of forecast gas production for the remainder of 2005 was hedged at an average price of $4.93 per Mcf, net to the well.

Market Resources enters into commodity-price-hedging arrangements with several banks and energy-trading firms. Generally the contracts allow some amount of credit before Market Resources is required to deposit collateral for out-of-the-money hedges. In some contracts the amount of credit varies depending on the credit rating assigned to Market Resources’ debt. Market Resources’ current ratings support individual counterparty lines of credit of $5 million to $40 million. If Market Resources credit ratings fall below investment grade (BBB- by S&P or Baa3 by Moody’s), counterparty credit generally falls to zero. In addition to the counterparty arrangements, Market Resources has a $200 million long-term revolving-credit facility with banks.

A summary of Market Resources hedging positions for equity production as of June 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

Second half of 2005	28.3	13.0	41.3	$4.78	$5.23	$4.93

First half of 2006	19.8	9.4	29.2	$5.19	$5.95	$5.44
Second half of 2006	20.1	9.6	29.7	5.19	5.95	5.44
12 months of 2006	39.9	19.0	58.9	5.19	5.95	5.44

First half of 2007	6.3	4.2	10.5	$5.64	$6.78	$6.09
Second half of 2007	6.4	4.2	10.6	5.64	6.78	6.09
12 months of 2007	12.7	8.4	21.1	5.64	6.78	6.09

First half of 2008	1.7	1.6	3.3	$5.93	$6.47	$6.20
Second half of 2008	1.7	1.7	3.4	5.93	6.47	6.20
12 months of 2008	3.4	3.3	6.7	5.93	6.47	6.20

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

Second half of 2005	550	184	734	$39.01	$34.70	$37.93

First half of 2006	471	72	543	$46.15	$53.44	$47.12
Second half of 2006	478	74	552	46.15	53.44	47.12
12 months of 2006	949	146	1,095	46.15	53.44	47.12

First half of 2007	109	72	181	$50.49	$50.87	$50.64
Second half of 2007	110	74	184	50.49	50.87	50.64
12 months of 2007	219	146	365	50.49	50.87	50.64

Market Resources held gas-price hedging contracts covering the price exposure for about 175.5 million MMBtu of gas and 2.2 MMbbl of oil as of June 30, 2005. A year earlier Market Resources’ hedging contracts covered 139.1 million MMBtu of natural gas and 1.5 MMbbl of oil. Market Resources does not hedge the price of equity NGL.

The following table summarizes changes in the fair value of hedging contracts from December 31, 2004, to June 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			21,924
Increase in gas and oil prices on futures markets			(104,774)
Contracts added since December 31, 2004			(64,953)
Hedge ineffectiveness			(343)
Net fair value of gas- and oil-hedging contracts outstanding at June 30, 2005			($215,647)

A table of the net fair value of gas-hedging contracts as of June 30, 2005, is shown below. About 65% 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 June 30, 2006	($141,343)
Contracts maturing between July 1, 2006 and June 30, 2007	(63,280)
Contracts maturing between July 1, 2007 and June 30, 2008	(9,976)
Contracts maturing after July 1, 2008	(1,048)
Net fair value of gas- and oil-hedging contracts at June 30, 2005	($215,647)

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 June 30,
	2005	2004
	(in millions)

Mark-to-market valuation – liability	($215.6)	($115.4)
Value if market prices of gas and oil decline by 10%	(105.8)	(55.6)
Value if market prices of gas and oil increase by 10%	(325.5)	(175.1)

Interest-Rate Risk Management

As of June 30, 2005, Questar had $933.2 million of fixed-rate long-term debt and no 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.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

The following table sets forth the Company’s purchases of common stock registered under Section 12 of the Exchange Act that occurred during the quarter ended June 30, 2005:

	Number of Shares Purchased*	Average Price per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares that May Yet Be Purchased Under the Plans
April 1, 2005 – April 30, 2005	12,452	$58.69	-	-

May 1, 2005 – May 31, 2005	24,308	$61.75	-	-

June 1, 2005 – June 30, 2005	34,107	$65.44	-	-

Total	70,867	$62.99	-	-

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

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The Company held its Annual Meeting on May 17, 2005. The following individuals were elected at the meeting to serve three year terms: Mr. Phillips S. Baker, Jr., Mr. L. Richard Flury, and Mr. James A. Harmon. Additionally, one director, Mr. M. W. Scoggins, was elected to serve a one-year term. There was no solicitation in opposition to the nominees. The following is a tabulation of the votes received by nominees elected at the meeting:

NAME	VOTES FOR	VOTES WITHHELD
P. S. Baker	74,952,391	2,255,557
L. R. Flury	74,034,236	3,173,711
J. A. Harmon	73,977,439	3,230,509
M. W. Scoggins	74,985,844	2,222,103

The Company’s directors are divided into three classes. Other directors whose terms extend beyond the meeting include: Teresa Beck, R. D. Cash, Robert E. Kadlec, Robert E. McKee II I , Gary G. Michael, Keith O. Rattie, Harris H. Simmons, and C. B. Stanley.

At the meeting, the Company’s shareholders also approved the Annual Management Incentive Plan II, with 73,345,919 shares voted in favor, 2,930,908 voted against, and 931,113 abstaining.

ITEM 5. OTHER INFORMATION

Patrick J. Early resigned as a director effective May 17, 2005, because he had reached the mandatory retirement age of 72. At the time of his retirement, Mr. Early was serving as Chair of the Executive Committee. Mr. Early’s retirement also leaves a vacancy on the Board of Directors.

Mr. Early was replaced as Chair of the Executive Committee by Gary G. Michael. Mr. Michael has served as a director of the Company since 1994 and has served as the chair of the Finance & Audit Committee, the Governance/Nominating Committee, and the Management Performance Committee. Mr. Michael was appointed as Chair of the Executive Committee on May 17, 2005. As Chair of the Executive Committee, Mr. Michael serves as Lead Director and conducts executive sessions of the Board of Directors. Shareholders may communicate with the Board of Directors, including Mr. Michael as the Lead Director, by sending a letter to the full Board, Mr. Michael, or the non-management directors in care of the Corporate Secretary at the Company headquarters, 180 East 100 South, P.O. Box 45433, Salt Lake City, Utah 84145-0433. The Corporate Secretary’s office has the authority to discard any solicitations, advertisements, or other inappropriate communications, but will forward any mail to the named director or group of directors that is not otherwise excluded.

James A. Harmon replaced Gary G. Michael as Chair of the Governance/Nominating Committee. Shareholders interested in submitting candidates for consideration as nominees for directors can submit in writing the names and qualifications of the candidates(s) to Mr. Harmon at the address for the Company’s headquarters provided above. Any nomination letters addressed to Mr. Harmon will be forwarded without screening. Individuals so nominated will be reviewed using the criteria applied by the Committee as set forth in the Committee’s charter published on the Company’s website (www.questar.com).

ITEM 6. EXHIBITS

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

Exhibit No.

Exhibit

31.1.

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

31.2.

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

32.

Certification signed by Keith O. Rattie and S. E. Parks, Questar’s Chairman, President and Chief Executive Officer and Senior Vice President 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 CORPORATION

(Registrant)

August 4, 2005

/s/Keith O. Rattie

Date

Keith O. Rattie, Chairman of the Board,

President and Chief Executive Officer

August 4, 2005

/s/S. E. Parks

Date

S. E. Parks, Senior Vice President and

Chief Financial Officer

Exhibits List

Exhibits

31.1.

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

31.2.

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

32.

Exhibit 31.1 .

CERTIFICATION

I, Keith O. Rattie, certify that:

I have reviewed this quarterly report of Questar Corporation on Form 10-Q for the period ending June 30, 2005;

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;

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;

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:

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;

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;

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

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 ;

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):

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

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.

August 4, 2005

By: /s/Keith O. Rattie

Date

Keith O. Rattie,

Chairman, President and Chief

Executive Officer

Exhibit 31.2.

CERTIFICATION

I, S. E. Parks, certify that:

I have reviewed this quarterly report of Questar Corporation on Form 10-Q for the period ending June 30, 2005;

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.

August 4, 2005

By /s/S. E. Parks

Date

S. E. Parks

Senior Vice President

and Chief Financial Officer

Exhibit No. 32.

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

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

(1)

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

(2)

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

QUESTAR CORPORATION

August 4, 2005

/s/Keith O. Rattie

Date

Keith O. Rattie

Chairman, President and Chief Executive Officer

August 4, 2005

/s/S. E. Parks

Date

S. E. Parks

Senior Vice President and Chief Financial Officer