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 September 30, 2005

[ ]

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

For the transition period from ___ to ___

Commission File Number 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 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 by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]

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

Class

Outstanding as of October 31, 2005

Common Stock, without Par

85,280,492 Shares

Value with attached Common

Stock Purchase Rights

Questar Corporation

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

TABLE OF CONTENTS

Page No.

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 nine months ended

September 30, 2005 and 2004

Condensed Consolidated Balance Sheets at September 30, 2005

and December 31, 2004

Condensed Consolidated Statements of Cash Flows for the nine months ended

September 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 6.

Exhibits

Signatures

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

The Company uses financial contracts to hedge its exposure to volatile natural gas, oil and NGL prices and to protect cash flow, returns on capital, net income and credit ratings from downward commodity-price movements. While hedging reduces the impact of declining prices, it may also limit future revenues from favorable price movements. 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 natural gas, oil and NGL prices.

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

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

Questar 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, oil and NGL on its Rockies leaseholds. Certain environmental groups oppose drilling on some of the Company’s federal and state leases.

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

frac spread

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

futures contract

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

gas

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

gross

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

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.

Mdth

One thousand decatherms.

Mdthe

One thousand decatherms of natural gas equivalents.

MMbbl

One million barrels.

MMBtu

One million British thermal units.

MMcf

One million cubic feet.

MMcfe

One million cubic feet of natural gas equivalents.

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).

psia

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

psig

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

reservoir

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

wet gas

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

working interest

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

SEC FILINGS AND WEBSITE INFORMATION

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 and Compliance 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 practical 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		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(in thousands, except per share amounts)
REVENUES
Market Resources	$446,746	$255,264	$1,105,980	$ 733,678
Questar Pipeline	22,584	18,345	59,583	54,227
Questar Gas	109,575	80,962	604,308	490,076
Corporate and other operations	4,005	5,654	13,572	15,375

TOTAL REVENUES	582,910	360,225	1,783,443	1,293,356

OPERATING EXPENSES
Cost of natural gas and other products sold	271,724	127,170	836,106	515,019
Operating and maintenance	98,169	81,313	280,958	242,296
Production and other taxes	30,864	22,087	83,499	67,581
Depreciation, depletion and amortization	63,542	52,566	182,174	160,243
Exploration	2,574	1,346	9,423	3,699
Abandonment and impairment of gas,
oil and other properties	1,712	2,848	4,610	9,541
Questar Gas rate-refund obligation		1,095		4,090

TOTAL OPERATING EXPENSES	468,585	288,425	1,396,770	1,002,469

OPERATING INCOME	114,325	71,800	386,673	290,887

Interest and other income	5,063	1,835	10,636	4,725
Earnings from unconsolidated affiliates	1,910	1,021	5,131	3,595
Debt expense	(17,869)	(16,753)	(51,234)	(51,324)

INCOME BEFORE INCOME TAXES	103,429	57,903	351,206	247,883
Income taxes	37,672	20,962	129,551	92,253

NET INCOME	$ 65,757	$ 36,941	$ 221,655	$ 155,630

EARNINGS PER COMMON SHARE
Basic	$ 0.78	$ 0.44	$ 2.62	$ 1.86
Diluted	0.75	0.43	2.55	1.82

Weighted average common shares outstanding
Used in basic calculation	84,930	83,864	84,674	83,627
Used in diluted calculation	87,353	85,882	87,043	85,496

Dividends per common share	$ 0.225	$ 0.215	$ 0.665	$ 0.635

See notes accompanying the consolidated financial statements

QUESTAR CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,	December 31,
	2005	2004
	(Unaudited)
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$ 10,964	$ 3,681
Accounts receivable, net	268,586	262,373
Unbilled gas accounts receivable	17,475	59,160
Hedging collateral deposits	243,270
Fair value of hedging contracts	30	9,334
Inventories, at lower of average cost or market
Gas and oil storage	77,173	66,944
Materials and supplies	31,675	18,993
Prepaid expenses and other	19,730	23,690
Purchased-gas adjustments	18,301	35,853
Deferred income taxes – current	151,945	6,968
Total current assets	839,149	486,996
Property, plant and equipment	5,322,500	4,877,771
Less accumulated depreciation, depletion and amortization	2,045,649	1,893,111
Net property, plant and equipment	3,276,851	2,984,660
Investment in unconsolidated affiliates	40,805	33,229
Goodwill	71,260	71,260
Regulatory assets	31,284	32,120
Other noncurrent assets, net	35,327	45,361
	$4,294,676	$3,653,626

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt	$ 92,000	$ 68,000
Accounts payable and accrued expenses	369,220	348,264
Questar Gas customer-credit balances	36,061	24,771
Rate-refund obligations	1,009	25,343
Fair value of hedging contracts	420,580	64,179
Total current liabilities	918,870	530,557
Long-term debt, less current portion	1,133,200	933,195
Deferred income taxes	581,908	553,401
Asset-retirement obligations	72,722	67,288
Pension and post-retirement benefits	43,133	47,919
Fair value of hedging contracts	147,545	14,471
Other long-term liabilities	81,764	67,237

Common shareholders' equity
Common stock	379,507	358,017
Retained earnings	1,300,941	1,135,718
Accumulated other comprehensive loss	(364,914)	(54,177)
Total common shareholders' equity	1,315,534	1,439,558
	$4,294,676	$3,653,626

See notes accompanying the consolidated financial statements

QUESTAR CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	9 Months Ended
	September 30,
	2005	2004
	(in thousands)

OPERATING ACTIVITIES
Net income	$ 221,655	$ 155,630
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	185,856	167,615
Deferred income taxes	72,997	65,064
Amortization of nonvested shares	2,990	1,723
Abandonment and impairment of gas, oil and other properties	4,610	9,541
Earnings from unconsolidated affiliates,
net of cash distributions	(789)	1,046
Net gain from asset sales	(4,722)	(76)
Other	390	218
	482,987	400,761
Changes in operating assets and liabilities	(177,876)	(6,479)
NET CASH PROVIDED FROM
OPERATING ACTIVITIES	305,111	394,282

INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(481,124)	(265,593)
Other investments	(6,787)	(1,000)
Total capital expenditures	(487,911)	(266,593)
Proceeds from disposition of assets	15,960	1,950
NET CASH USED IN INVESTING ACTIVITIES	(471,951)	(264,643)

FINANCING ACTIVITIES
Common stock issued	15,809	21,099
Common stock repurchased	(9,246)	(3,361)
Long-term debt repaid	(8)	(71,993)
Long-term debt issued	200,000
Change in short-term debt	24,000	(43,200)
Checks in excess of cash balances		7,400
Dividends paid	(56,432)	(53,234)
Other		(255)
NET CASH PROVIDED FROM
(USED IN) FINANCING ACTIVITIES Change in cash and cash equivalents Beginning cash and cash equivalents	174,123	(143,544)
	7,283	(13,905)
	3,681	13,905
Ending cash and cash equivalents	$ 10,964	$ -

See notes accompanying the consolidated financial statements

QUESTAR CORPORATION

NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS

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 nine months ended September 30, 2005, are not necessarily indicative of the results that may be expected for the year ending December 31, 2005, due to a variety of factors discussed in the Forward-Looking Statements and Risk Factors section of this report. Interim consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. For further information please refer to the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K, 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. As a result of the court’s order, Questar Gas recorded a $29 million liability for a potential refund to gas-distribution customers. This liability included 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. Questar Gas reduced its rates on September 1, 2004, to eliminate the collection of gas-processing costs and on October 1, 2004, began refunding previously collected costs, plus interest, over a 12-month period.

In response to a Questar Gas petition, the PSCU clarified that its order did not preclude recovery of ongoing and certain past-processing costs. 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. 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 annual cost of operating the gas-processing plant. The Wyoming share has been recovered in rates.

In October 2005 Questar Gas, the Utah Division of Public Utilities and the Committee of Consumer Services, a Utah state agency, submitted a stipulation to the PSCU to resolve issues related to cost recovery of carbon dioxide processing activities. The PSCU held a hearing on October 20 to consider the stipulation and will issue an order at a later date. The stipulation provides for the recovery of $3.6 million of costs that were expensed during the period February 1, 2005 through September 30, 2005, as well as going forward costs that have been about $5.7 million on an annual basis.

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 was 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 accrued a potential liability equal to any liquid revenues from the dew point plant. Through 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 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 with customers was approved July 26, 2005, and 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; and (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. Questar Pipeline recorded the impact of the settlement in third quarter 2005 increasing liquid revenues by $2.7 million and net income by $1.7 million.

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. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Changes in asset-retirement obligations were as follows:

	2005	2004
	(in thousands)

Balance at January 1,	$67,288	$61,358
Accretion	3,148	1,896
Additions	3,010	1,593
Revisions		695
Retirements and properties sold	(724)	(365)
Balance at September 30,	$72,722	$65,177

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 September 30, 2005, approximately $3.6 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			9 Months Ended
	September 30,			September 30,
	2005		2004	2005	2004
			(in thousands)

Weighted-average basic common shares outstanding	84,930		83,864	84,674	83,627
Potential number of shares issuable from exercising
stock options and from nonvested restricted shares		2,423	2,018	2,369	1,869
Weighted-average diluted common shares Outstanding	87,353		85,882	87,043	85,496

In the first nine months of 2005, Questar issued 813,000 shares for the Long-Term Stock Incentive Plan and the Employee Investment Plan.

Note 5 – Share-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 equals the market price on the date of grant. The Company adopted the pro forma income disclosure features described in SFAS 123 “Accounting for Stock-Based Compensation” as amended by SFAS 148 “Accounting for Stock-Based Compensation-Transition and Disclosure.” The following table shows pro forma income had stock options been expensed based on fair value calculated using the Black-Scholes-Merton model:

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
		(in thousands)

Net income, as reported	$65,757	$36,941	$221,655	$155,630
Deduct stock-based compensation expense under fair-value based methods	(402)	(652)	(1,206)	(2,313)
Pro forma net income	$65,355	$36,289	$220,449	$153,317

Earnings per share
Basic, as reported	$ 0.78	$ 0.44	$ 2.62	$ 1.86
Basic, pro forma	0.77	0.43	2.60	1.83
Diluted, as reported	0.75	0.43	2.55	1.82
Diluted, pro forma	0.75	0.42	2.53	1.79

Net income as reported in the table above, reflects compensation costs related to restricted stock awards. Restricted shares are valued at the market price on the grant date and amortized to expense over the vesting period. Expense for the nine months ended September 30, 2005 and 2004, amounted to $3.0 million and $1.7 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 recognition of compensation costs for all share based payments granted, modified or settled after the date of implementation as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. 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		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
		(in thousands)

REVENUES FROM UNAFFILIATED CUSTOMERS
Market Resources	$446,746	$255,264	$1,105,980	$ 733,678
Questar Pipeline	22,584	18,345	59,583	54,227
Questar Gas	109,575	80,962	604,308	490,076
Corporate and other operations	4,005	5,654	13,572	15,375
	$582,910	$360,225	$1,783,443	$1,293,356

REVENUES FROM AFFILIATED COMPANIES
Market Resources	$ 34,746	$ 29,333	$ 108,571	$ 97,780
Questar Pipeline	20,182	22,083	64,124	66,170
Questar Gas	1,769	1,100	4,400	3,254
Corporate and other operations	384	3,005	1,459	14,611
	$ 57,081	$ 55,521	$ 178,554	$ 181,815

OPERATING INCOME (LOSS)
Market Resources	$106,414	$ 64,431	$ 292,195	$ 199,666
Questar Pipeline	20,218	18,406	55,921	53,744
Questar Gas	(12,519)	(12,451)	35,310	33,020
Corporate and other operations	212	1,414	3,247	4,457
	$114,325	$ 71,800	$ 386,673	$ 290,887

NET INCOME (LOSS)
Market Resources	$ 65,279	$ 37,211	$ 176,661	$ 115,629
Questar Pipeline	9,223	8,036	25,155	23,381
Questar Gas	(9,905)	(9,775)	15,361	12,537
Corporate and other operations	1,160	1,469	4,478	4,083
	$ 65,757	$ 36,941	$ 221,655	$ 155,630

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		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(in thousands)

Service cost	$ 2,184	$ 2,019	$ 6,553	$ 6,058
Interest cost	5,170	4,857	15,510	14,572
Expected return on plan assets	(4,947)	(4,710)	(14,840)	(14,131)
Prior service and other costs	320	481	959	1,442
Recognized net-actuarial loss	877	526	2,631	1,579
Amortization of early-retirement costs	725	719	2,175	2,156
Qualified pension expense	$ 4,329	$ 3,892	$ 12,988	$ 11,676

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 September 30,		9 Months Ended September 30,
	3 Months Ended September 30,		9 Months Ended September 30,
	2005	2004	2005	2004
		(in thousands)

Service cost	$ 200	$ 196	$ 600	$ 588
Interest cost	1,150	1,286	3,450	3,930
Expected return on plan assets	(739)	(762)	(2,217)	(2,286)
Special termination benefits		41		123
Amortization of transition obligation	469	470	1,408	1,409
Amortization of losses	20	64	61	256
Accretion of regulatory liability	200	200	600	600
Postretirement benefits expense	$1,300	$1,495	$3,902	$4,620

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 September 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:

	9 Months Ended September 30,
	9 Months Ended September 30,
	2005	2004
	(in thousands)

Revenues	$15,547	$12,222
Operating income	10,059	7,309
Income before income taxes	10,154	7,325

Note 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 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		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(in thousands)

Net income	$ 65,757	$ 36,941	$ 221,655	$ 155,630
Other comprehensive income loss
Unrealized loss on energy- hedging transactions	(352,386)	(49,269)	(500,204)	(113,858)
Income taxes	133,237	18,440	189,467	42,641
Net other comprehensive loss	(219,149)	(30,829)	(310,737)	(71,217)
Total comprehensive income (loss)	($153,392)	$ 6,112	($89,082)	$ 84,413

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

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

Unrealized loss on energy-hedging transactions	($352,887)	($42,150)
Additional pension liability	(12,027)	(12,027)
Accumulated other comprehensive loss	($364,914)	($54,177)

Note 10 – 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. During the third quarter of 2005, Questar Pipeline withdrew its proposal with the Los Angeles Department of Water and Power to complete conversion of the pipeline for natural gas service. Questar Pipeline has been holding discussions with other potential purchasers of the pipeline. Depending upon the results of these discussions, Questar Pipeline may be required to recognize an impairment in the value of Southern Trails in the near term. The magnitude of any such impairment is not known but could be material. Questar Pipeline performed an impairment test for third 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.

Note 11 – Recent Accounting Developments

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 third quarter of 2005 of $65.8 million or $0.75 per diluted share compared to $36.9 million or $0.43 per share for the third quarter of 2004. Questar’s net income was $221.7 million or $2.55 per diluted share in the first nine months of 2005 compared to $155.6 million or $1.82 per share for the first nine months of 2004. Following are comparisons of net income by line of business:

	3 Months Ended September 30,		9 Months Ended September 30,
	2005	2004	2005	2004
	(in thousands, except per share amounts)
Net income (loss)
Market Resources	$65,279	$37,211	$176,661	$115,629
Questar Pipeline	9,223	8,036	25,155	23,381
Questar Gas	(9,905)	(9,775)	15,361	12,537
Corporate and other operations	1,160	1,469	4,478	4,083
Total	$65,757	$36,941	$221,655	$155,630

Earnings per diluted common share	$0.75	$0.43	$2.55	$1.82

Market Resources net income was 75% higher in the third quarter of 2005 and 53% higher for the first nine months of 2005 compared to the same periods of 2004. The increase in net income was driven by higher prices and higher production for gas, oil and NGL and increased investment base at Wexpro. In Gas Management, a 55% increase in year-to-date 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 15% in the third quarter of 2005 compared to the 2004 period as a result of a settlement reached with shippers on the sharing of liquid revenues. Questar Pipeline net income increased 8% in the first nine months of 2005 due to the settlement and new transportation contracts.

Questar Gas’s seasonal loss in the third quarter of 2005 was about the same as the year-earlier quarter. Total margin from gas sales increased due to a 3.1% growth in the number of customers but decreased due to a 4% decrease in temperature-adjusted gas usage per customer. Questar Gas increased net income by 23% in the first nine months of 2005. Total margin from gas sales rose due to the increase in the number of customers and a 2% 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 natural 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 natural gas and oil, provides risk-management services and through Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir.

Market Resources Consolidated Results

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

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

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(in thousands)
OPERATING INCOME
Revenues
Natural gas sales	$131,466	$ 88,799	$352,985	$268,495
Oil and NGL sales	31,254	21,933	86,178	63,151
Cost-of-service gas operations	32,051	27,307	97,704	87,753
Energy marketing	248,069	121,792	568,979	340,733
Gas gathering, processing and other	38,652	24,766	108,705	71,326
Total revenues	481,492	284,597	1,214,551	831,458
Operating expenses
Energy purchases	243,972	121,885	559,201	337,765
Operating and maintenance	55,554	41,568	151,909	119,935
Production and other taxes	25,413	17,180	67,619	52,332
Depreciation, depletion and amortization	44,083	34,238	125,199	105,271
Exploration	2,574	1,346	9,423	3,699
Abandonment and impairment of gas, oil and other properties	1,712	2,848	4,610	9,541
Wexpro Agreement – oil-income sharing	1,770	1,101	4,395	3,249
Total operating expenses	375,078	220,166	922,356	631,792
Operating income	$106,414	$ 64,431	$292,195	$199,666

OPERATING STATISTICS
Questar E&P production volumes
Natural gas (MMcf)	25,681	21,831	71,930	65,546
Oil and NGL (Mbbl)	593	571	1,762	1,717
Total production (bcfe)	29.2	25.3	82.5	75.8
Average daily production (MMcfe)	318	275	302	277
Average commodity prices, net to the well
Average realized price (including hedges)
Natural gas (per Mcf)	$ 5.12	$ 4.07	$ 4.91	$ 4.10
Oil and NGL (per bbl)	$ 43.04	$ 31.83	$ 40.61	$ 30.28
Average sales price (excluding hedges)
Natural gas (per Mcf)	$ 6.66	$ 4.92	$ 5.89	$ 4.89
Oil and NGL (per bbl)	$ 57.65	$ 40.55	$ 50.62	$ 35.89
Wexpro investment base at September 30, net
of depreciation and deferred income taxes (millions)	$ 197.6	$ 165.0
Natural gas gathering volumes (in thousands of MMBtu)
For unaffiliated customers	35,619	32,767	101,693	99,225
For Questar Gas	10,252	8,915	32,734	27,821
For other affiliated customers	17,895	12,995	48,157	40,889
Total gathering	63,766	54,677	182,584	167,935
Gathering revenue (per MMBtu)	$ 0.25	$ 0.22	$ 0.25	$ 0.21
Natural gas and oil marketing volumes (Mdthe)
For unaffiliated customers	32,064	24,973	87,320	66,303
For affiliated customers	22,455	20,188	67,102	61,234
Total marketing	54,519	45,161	154,422	127,537

Questar E&P

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

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

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

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

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

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

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

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

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

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

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

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 September 30, 2005, are summarized in Part I, Item 3 of this report.

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

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

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

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

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(per Mcfe)

Lease-operating expense	$0.52	$0.52	$0.55	$0.51
Production taxes	0.61	0.44	0.53	0.43
Lifting costs	1.13	0.96	1.08	0.94
Depreciation, depletion and amortization	1.19	1.06	1.17	1.03
General and administrative expense	0.29	0.29	0.31	0.30
Allocated-interest expense	0.21	0.22	0.21	0.21
Total	$2.82	$2.53	$2.77	$2.48

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

Pinedale Anticline Drilling Activity

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

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

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

Uinta Basin

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

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

Rockies Legacy

In the Vermillion Basin on the southwest Wyoming-northwest Colorado border, Market Resources continues to evaluate the potential of several formations at depths of 10,000 to 15,000 feet under the company’s 140,000 net leasehold acres. As of October 31, 2005, the company had recompleted two older wells, drilled and completed two new wells, had one well waiting on completion and was drilling one well. The first new well, Alkali Gulch Unit Well No 1, was completed in June 2005 and produced an average of 1.93 MMcf per day from the Baxter, Frontier and Dakota formations during the first 141 days. On October 31 the well was producing about 1.6 MMcf per day. The second new well, Canyon Creek 41, went to sales on September 21, 2005. During the first 30 days of production, the well averaged 2.95 MMcf per day from the Baxter and Frontier formations. The well was producing 1.9 MMcf per day on October 31, 2005. After delays related to mechanical problems, the third new well, Hiawatha Deep Unit No. 5 should be completed and turned to sales in mid-November, 2005. The company currently plans to drill about 12 new wells in the Vermillion Basin in 2006.

Midcontinent

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

Wexpro

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

Gas Management

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

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

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

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

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

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

Energy Trading

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

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 third quarter and first nine months of 2005 compared with the same periods of 2004:

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(in thousands)
OPERATING INCOME
Revenues
Transportation	$26,643	$26,311	$ 79,897	$ 79,285
Storage	9,156	9,322	27,986	28,298
Carbon dioxide processing	1,405	1,946	4,872	5,667
Liquid revenues and other	5,562	2,849	10,952	7,147
Total revenues	42,766	40,428	123,707	120,397
Operating expenses
Operating and maintenance	13,522	13,388	40,990	40,710
Other taxes	1,686	1,673	4,943	5,065
Depreciation and amortization	7,340	6,961	21,853	20,878
Total operating expenses	22,548	22,022	67,786	66,653
Operating income	$20,218	$18,406	$ 55,921	$ 53,744

OPERATING STATISTICS
Natural gas transportation volumes (in Mdth)
For unaffiliated customers	71,257	60,128	188,252	169,112
For Questar Gas	16,594	14,825	86,545	87,293
For other affiliated customers	9,072	5,506	17,553	14,974
Total transportation	96,923	80,459	292,350	271,379
Transportation revenue (per dth)	$ 0.27	$ 0.33	$ 0.27	$ 0.29
Firm-daily transportation demand at September 30, (Mdth)	1,832	1,643

Questar Pipeline’s net income was $9.2 million in the third quarter of 2005 compared with $8.0 million in the third quarter of 2004. For the first nine months of 2005, Questar Pipeline’s net income was $25.2 million compared with $23.4 million in the year-earlier period. Revenues increased in the 2005 period due to new transportation contracts and settlement of a liquids revenue sharing dispute with customers. See Note 2 in the Notes Accompanying the Consolidated Financial Statements in this report for a discussion of the settlement. The earnings increase in the first nine months of 2005 included $237,000 after-tax gains from the sale of assets and the capitalization of $899,000 of carrying costs on construction projects.

Revenues

Gas transportation volumes increased in the third quarter of 2005 and first nine months of 2005 over the prior year periods due to new transportation contracts. Following is a summary of major changes in Questar Pipeline’s revenues for the three and nine months ended September 30, 2005, compared with the same periods of 2004:

	3 Months Ended September 30, 2005 Compared with 2004		9 Months Ended September 30, 2005 Compared with 2004
	(in thousands)
Transportation
New transportation contracts	$ 996	$ 2,319
Expiration of transportation contracts	(450)	(1,082)
Elimination of Gas Research Institute Surcharge	(100)	(578)
Other transportation	(114)	(47)
Storage	(166)	(312)
Carbon dioxide processing	(541)	(795)
Liquid revenues and other
Change in liquid revenues before credit	75	289
Reversal of credit of Kastler liquid revenues	2,723	2,723
Park and loan revenue	(227)	496
Other	142	297
Increase	$ 2,338	$ 3,310

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 September 30, 2005, Questar Pipeline had firm-transportation contracts of 1,832 Mdth per day compared with 1,643 Mdth per day as of September 30, 2004. 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 10.9 years as of September 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 8.2 years as of September 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 1% in the third quarter of 2005 and 1% in the first nine months 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 $0.140 in the first nine months of 2005 compared with $0.150 in the first nine months of 2004. Operating and maintenance includes processing and storage costs.

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 service, 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 September 30, 2005, construction of the expansion was nearly complete. Questar Pipeline began partial service in September 2005 and expects to begin full service in the fourth quarter 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 the plant’s firm capacity and pays the cost of service for operating the plant.

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 in the Notes Accompanying the Consolidated Financial Statements in this report 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 third quarter and first nine months of 2005 compared with the same periods of 2004:

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(in thousands)
OPERATING INCOME
Revenues
Residential and commercial sales	$ 87,849	$ 64,342	$541,632	$432,201
Industrial sales	9,873	10,040	28,974	37,436
Transportation for industrial customers	1,321	1,348	4,226	4,801
Other	12,301	6,332	33,876	18,892
Total revenues	111,344	82,062	608,708	493,330
Cost of natural gas sold	81,042	54,394	444,998	336,821
Margin	30,302	27,668	163,710	156,509
Operating expenses
Operating and maintenance	27,478	25,569	84,395	79,034
Other taxes	3,468	2,893	9,932	9,137
Depreciation and amortization	11,875	10,562	34,073	31,228
Rate-refund obligation		1,095		4,090
Total operating expenses	42,821	40,119	128,400	123,489
Operating income (loss)	($ 12,519)	($ 12,451)	$ 35,310	$ 33,020

OPERATING STATISTICS
Natural gas volumes (in Mdth)
Residential and commercial sales	9,081	8,307	65,843	61,624
Industrial sales	1,348	1,883	4,445	6,908
Transportation for industrial customers	7,218	7,661	22,941	25,807
Total deliveries	17,647	17,851	93,229	94,339
Natural gas revenue (per dth)
Residential and commercial sales	$ 9.67	$ 7.74	$ 8.23	$ 7.01
Industrial sales	7.32	5.33	6.52	5.42
Transportation for industrial customers	$ 0.18	$ 0.18	$ 0.18	$ 0.19
Heating degree days
colder (warmer) than normal	17%	29%	(2%)	6%
Average temperature adjusted usage
per customer (dth)	9.1	9.5	77.2	76.0
Customers at September 30,	803,196	778,992

Questar Gas incurred a seasonal loss of $9.9 million in the third quarter of 2005 compared with a loss of $9.8 million in the third quarter of 2004. For the first nine months of 2005 Questar Gas earned $15.4 million compared with $12.5 million in the first nine months of 2004.

Margin Analysis

Questar Gas’s margin (revenues less gas costs) increased $2.6 million in the third quarter of 2005 compared to the third quarter of 2004 and increased $7.2 million in the first nine months of 2005 compared to the same period of 2004. Following is a summary of major changes in Questar Gas’s margin:

		3 Months Ended September 30, 2005 Compared with 2004	9 Months Ended September 30, 2005 Compared with 2004
	(in thousands)

New customers		$ 418	$ 3,550
Increased (decreased) usage per customer		(610)	1,831
2004 carbon dioxide processing revenues collected from customers		(1,095)	(4,090)
Interest on past-due receivables		331	1,218
Annual true-up of unbilled revenues		2,497	2,497
Other – includes customers shifting between rate schedules		1,093	2,195
Increase		$ 2,634	$ 7,201

Residential and commercial sales volumes increased 9% in the third quarter of 2005 over the third quarter of 2004 as a result of increased customers and customers changing from the industrial rate schedules. These increases were partially offset by warmer weather and decreased usage per customer. Residential and commercial sales volumes increased 7% in the first nine months of 2005 compared with the first nine months of 2004 as increased customers and increased usage per customer offset the impact of warmer weather. At September 30, 2005, Questar Gas was serving 803,196 customers, a 3.1% 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 down 4% in the third quarter of 2005 and up 2% in the first nine months 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 17% colder than normal in the third quarter of 2005 compared with 29% colder than normal in the third quarter of 2004. For the first nine months of 2005, weather was 2% 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 10% in the third quarter of 2005 and 16% in the first nine months of 2005 compared with 2004 primarily driven by lower power-generation requirements in the current period and customers changing to the residential and commercial rate schedules.

Expenses

Cost of natural gas sold increased 49% in the third quarter of 2005 and 32% in the first nine months 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 September 30, 2005, Questar Gas had an $18.3 million balance in the purchased-gas adjustment account representing gas costs incurred but not yet recovered from customers. On October 25, 2005, Questar Gas filed a request for a 20% increase in Utah rates to cover higher costs of purchased natural gas. Combined with a 14% increase in June and other changes, customer rates will be 42% higher than the prior year if the request is approved.

Operating and maintenance expenses increased 7% in the third quarter of 2005 and the first nine months of 2005 compared with 2004. The increases are due to higher labor and labor overhead costs and bad debt costs.

Depreciation expense increased 12% in the third quarter of 2005 and 9% in the first nine months 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 the Consolidated Financial Statements 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’ earnings before tax increased to $1.9 million in the 2005 quarter versus $1.0 million in 2004 and $5.0 million in the first nine months of 2005 compared to $3.5 million for the same period last year. Rendezvous gathering volumes increased 80% in the third quarter and 48% in the first nine months of 2005 compared to the year earlier periods.

Debt expense

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

Interest and Other Income

Interest and other income was higher in the third quarter and nine months ended 2005 compared to the same periods of 2004. Questar Gas’s return on gas stored underground increased because of higher rates and inventory valuations. The higher earnings also reflect interest received on hedging collateral deposits. Gains from asset sales added $1.2 million before tax in the third quarter of 2005.

Income taxes

The effective combined federal and state income tax rate for the first nine months was 36.9% in 2005 and 37.2% in 2004.

Liquidity and Capital Resources

Operating Activities

	9 Months Ended
	September 30,
	2005	2004
	(in thousands)

Net income	$ 221,655	$155,630
Noncash adjustments to net income	261,332	245,131
Changes in operating assets and liabilities	(177,876)	(6,479)
Net cash provided from operating activities	$ 305,111	$394,282

Net cash provided from operating activities decreased 23% in the first nine months of 2005 compared to the first nine months of 2004. Higher net income was more than offset by hedging collateral calls amounting to $243.3 million. The interest-bearing hedging collateral deposits were required in response to higher sales prices for natural gas and oil. As of October 31, 2005, collateral on deposit had declined to $60.8 million as a result of the elimination of credit support requirements with several counterparties, increases in the amount of credit allowed by other counterparties before Market Resources is required to deposit collateral and lower commodity prices.

Investing Activities

A comparison of capital expenditures for the first nine months of 2005 and 2004 plus forecasts for calendar years 2005 and 2006 are presented below:

			Forecasts
	9 Months Ended		12 Months Ended
	September 30,		December 31,
	2005	2004	2005		2006
	(in thousands)

Market Resources	$380,137	$191,708	$525,100	$490,400
Questar Pipeline	56,643	14,486	82,500	122,400
Questar Gas	49,991	58,625	83,000	99,100
Corporate and other operations	1,140	1,774	1,500	800
Total	$487,911	$266,593	$692,100	$712,700

Market Resources’ expanded Rockies, Uinta Basin and Midcontinent drilling programs and construction of the water and condensate gathering system to serve the Pinedale Anticline represented the majority of the increase in capital expenditures for the first nine months of 2005 compared to the 2004 period. Completion of the water and condensate gathering system in 2005 is the primary reason for the decrease in 2006 capital expenditures.

Financing Activities

Net cash flow provided from operating activities, excluding $243.3 million of hedging collateral deposits, was sufficient to fund net capital expenditures and pay dividends in the first nine months of 2005. In the third quarter, the Company borrowed $200 million available on Market Resources’ revolving loan facility to meet the calls and issued $24 million of commercial paper. Total debt was 48% of total capital at September 30, 2005.

Short-term debt at September 30, 2005, was comprised of commercial paper with an average interest rate of 3.9%. The Company had $270 million of short-term lines of credit at September 30, 2005.

Net cash used in investing activities include proceeds of $13.0 million, which approximates book value, from the second quarter 2005 sale of data-hosting assets.

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

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

A summary of Market Resources hedging positions for equity production as of September 30, 2005, is shown below. Prices are net to the well. Currently all hedges are fixed-price swaps with creditworthy counterparties, allowing Market Resources to achieve a known price for a specific volume of production delivered into a regional sales point. The swap price is then reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price.

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

Fourth quarter 2005	16.1	6.5	22.6	$5.12	$5.23	$5.15

First half of 2006	23.1	10.3	33.4	5.56	6.24	5.77
Second half of 2006	23.5	10.4	33.9	5.56	6.24	5.77
12 months of 2006	46.6	20.7	67.3	5.56	6.24	5.77

First half of 2007	11.4	7.6	19.0	6.40	7.40	6.80
Second half of 2007	11.5	7.7	19.2	6.40	7.40	6.80
12 months of 2007	22.9	15.3	38.2	6.40	7.40	6.80

First half of 2008	3.4	1.7	5.1	6.22	6.47	6.30
Second half of 2008	3.4	1.7	5.1	6.22	6.47	6.30
12 months of 2008	6.8	3.4	10.2	$6.22	$6.47	$6.30

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

Fourth quarter 2005	303	110	413	$41.60	$40.36	$41.27

First half of 2006	561	163	724	49.42	61.42	52.12
Second half of 2006	570	166	736	49.42	61.42	52.12
12 months of 2006	1,131	329	1,460	49.42	61.42	52.12

First half of 2007	217	145	362	57.48	57.86	57.63
Second half of 2007	221	147	368	57.48	57.86	57.63
12 months of 2007	438	292	730	$57.48	$57.86	$57.63

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

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

			(in thousands)

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

A table of the net fair value of gas-hedging contracts as of September 30, 2005, is shown below. About 74% of the fair value of all contracts will settle and be reclassified from other comprehensive income in the next 12 months:

	(in thousands)

Contracts maturing by September 30, 2006	($420,550)
Contracts maturing between October 1, 2006 and September 30, 2007	(123,222)
Contracts maturing between October 1, 2007 and September 30, 2008	(22,252)
Contracts maturing after October 1, 2008	(2,071)
Net fair value of gas- and oil-hedging contracts at September 30, 2005	($568,095)

The following table shows sensitivity of the mark-to-market valuation of gas and oil price-hedging contracts to changes in the market price of gas and oil:

	At September 30,
	2005	2004
	(in millions)

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

Interest-Rate Risk Management

As of September 30, 2005, Questar had $933.2 million of fixed-rate long-term debt and $200 million of variable-rate long-term debt.

ITEM 4. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures.

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by the report (the Evaluation Date). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the Company’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company, including its consolidated subsidiaries, required to be included in the Company’s reports filed or submitted under the Exchange Act. The Company’s Chief Executive Officer and Chief Financial Officer also concluded that the controls and procedures were effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management including its principal executive and financial officers or persons performing similar functions as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls.

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

See Note 2 in the Notes Accompanying the Consolidated Financial Statements in this report for a discussion of the regulatory proceedings involving Questar Gas’s processing costs and Questar Pipeline’s FGRP.

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

ITEM 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 September 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
July 1, 2005 – July 31, 2005	4,209	$67.39	-	-

August 1, 2005 – August 31, 2005	43,995	$75.38	-	-

September 1, 2005 – September 30, 2005	33,582	$82.98	-	-

Total	81,786	$78.09	-	-

*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 share s of restricted stock forfeited when failing to satisfy vesting conditions and any shares delivered or attested to when exercising stock options.

ITEM 6. EXHIBITS

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

Exhibit No.

Exhibit

3.2.

Bylaws as amended effective October 24, 2005.

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)

November 4, 2005

/s/Keith O. Rattie

Date

Keith O. Rattie, Chairman of the Board,

President and Chief Executive Officer

November 4, 2005

/s/S. E. Parks

Date

S. E. Parks, Senior Vice President and

Chief Financial Officer

Exhibits List

Exhibits

3.2.

Bylaws as amended effective October 24, 2005.

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 3.2

AMENDED BYLAWS

QUESTAR CORPORATION

A Utah Corporation

OFFICES

SECTION 1. The principal office shall be in Salt Lake City, Salt Lake County, Utah. The Corporation may also have an office at such other places as the Board of Directors may from time to time appoint or the business of the Corporation may require.

SEAL

SECTION 2. The corporate seal shall be inscribed with the name of the Corporation, the year of its organization, and the words "Corporate Seal, Utah." The seal may be used by causing it, or a facsimile thereof, to be impressed, affixed or reproduced.

STOCKHOLDERS' MEETINGS

SECTION 3. All meetings of the stockholders shall be held at the office of the Corporation in Salt Lake City, Salt Lake County, State of Utah or any other convenient location within the United States as the Board of Directors may fix.

SECTION 4. The annual meeting of stockholders shall be held at such date and time as shall be designated from time to time by the Board of Directors and stated in the notice of the meeting, at which stockholders shall elect, by plurality vote, directors equal in number to those with terms that expire as of the same date and transact such other business as may properly be brought before the meeting.

SECTION 5. Special meetings of the stockholders, for any proper purpose or purposes may be called by the Board of Directors. Special meetings shall be called by the Chairman or Secretary at the request in writing of the holders entitled to cast at least 10 percent of the votes that all stockholders are entitled to cast on any issue proposed or to be considered at the particular meeting. Such written request shall state the purpose or purposes of the proposed meeting. Upon a request from holders entitled to call a special meeting, the Board of Directors shall determine a place and time for such meeting, which time (other than special meetings called pursuant to Utah's Control Shares Acquisition Act) shall be not less than ninety (90) nor more than one hundred and twenty (120) days after the receipt and determination of the validity of such request; and a record date for the determination of stockholders entitled to vote at such meeting. Following such receipt and determination, notice shall be delivered to the stockholders entitled to vote at such meeting in the manner set forth in the Bylaws that a meeting will be held at the time and place so determined. The Board of Directors or the Chairman of the Board of Directors may determine rules and procedures for the conduct of the meeting.

SECTION 6. Holders of a majority of the stock issued and outstanding and entitled to vote, present in person or represented by proxy, shall be requisite and shall constitute a quorum at all meetings of the stockholders for the transaction of business, except as otherwise provided by law, by the Articles of Incorporation, or by these Bylaws. Abstentions, withheld votes, and broker non-votes are counted for purposes of determining whether a quorum is present. If, however, such majority shall not be present or represented at any meeting of the stockholders, the stockholders entitled to vote, present in person or by proxy, shall have power to adjourn the meeting, from time to time, without notice other than announcement at the meeting, until such requisite amount of voting stock shall be present. At such adjourned meeting at which the requisite amount of voting stock shall be represented, any business may be transacted that might have been transacted at the meeting as originally notified.

SECTION 7. The Secretary shall give, but in case of his failure, any other officer of the Corporation may give, written or printed notice to the stockholders stating the place, day and hour of each meeting of stockholders and, in case of a special meeting, the purpose or purposes for which the meeting is called. Such notice shall be given not less than ten (10) nor more than sixty (60) days before the date of the meeting.

SECTION 8. Notice of annual or special meeting of stockholders may be given personally, by mail or private carrier, by electronic dissemination, or by any other means recognized under applicable state and federal law. If given by mail, such notice shall be deemed to be delivered when deposited in the United States mail or private carrier, addressed to the stockholder at such address as it appears on the stock transfer books of the Corporation, with postage prepaid.

SECTION 9. At each meeting of the stockholders, every stockholder having the right to vote shall be entitled to vote in person, or by proxy appointed by an instrument in writing, subscribed by such stockholder and bearing a date not more than eleven months prior to the meeting, unless the instrument provides for a longer period. Each stockholder shall have one vote for each share of stock registered in the stockholder's name on the books of the Corporation as of the record date set for such meeting. The vote for directors, and, upon the demand of any stockholder, the vote upon any question before the meeting, shall be by ballot. All elections shall be had and all questions decided by a plurality vote, except as otherwise provided in these Bylaws, the Articles of Incorporation, or applicable law. For purposes of determining whether a plurality vote, a majority vote or a supermajority vote (if required by the Bylaws, the Articles of Incorporation, or applicable law) has been achieved, only votes cast "for" or "against" are included. Abstentions, withheld votes, and broker non-votes are not considered votes cast.

SECTION 10. A complete list of stockholders entitled to vote at the ensuing election shall be prepared and be available for inspection at the Corporation's principal office by any stockholder beginning two business days after notice is given of the meeting for which the list was prepared and continuing throughout the meeting. The list shall be arranged by voting group and by class or series of shares within each voting group and be alphabetical within each voting group or class. The list shall indicate each stockholder's name, address, and number of voting shares.

A stockholder, directly or through an agent or attorney, has the right to inspect and copy, at his expense, the list of stockholders prepared in connection with each meeting of stockholders. The stockholder must make a written request to examine the list and must examine it during the Corporation's regular business hours.

SECTION 11. Business transacted at all special meetings of the stockholders shall be confined to the objects stated in the call and notice.

SECTION 12. Only proposals properly brought before the Corporation's annual or special meeting of stockholders may be considered and voted upon by stockholders. A proposal shall be properly brought before the meeting if it is specified in the notice of such meeting (or any supplement to such notice) mailed by the Corporation to the stockholders, or if it is otherwise properly brought before the meeting by or at the direction of the Corporation's Board of Directors, or if such proposal is otherwise properly brought before an annual meeting by a stockholder entitled to vote at such meeting who has complied with the procedures specified in this section of the Corporation's Bylaws. A stockholder desiring to make a proposal before the annual meeting that is not contained in the notice of such meeting distributed, by order of the Board of Directors, to the Corporation's stockholders must give timely notice of the proposal, in proper written form, to the Corporation's Secretary at the Corporation's principal executive offices.

To be timely, a stockholder's notice to the Secretary must be delivered to or mailed and received at the principal executive offices of the Corporation not less than ninety (90) days nor more than one hundred twenty (120) days prior to the anniversary date of the immediately preceding annual meeting of stockholders; provided, however, that in the event that the annual meeting is called for a date that is not within twenty-five (25) days before or after such anniversary date, notice by the stockholder in order to be timely must be so received not later than the close of business on the tenth (10^th) day following the day on which such notice of the date of the annual meeting was mailed or such public disclosure of the date of the annual meeting was made, whichever first occurs.

To be proper written form, a stockholder’s notice to the Secretary must set forth the following information: (a) a clear and concise statement of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (b) the name and record address of such stockholder, (c) the number of shares of the Corporation's common stock that are owned beneficially or of record by such stockholder, (d) a description of all arrangements or understandings between such stockholder and any other person or persons (including their names) in connection with the proposal of such business by such stockholder and any material interest of such stockholder in such business, and (e) a representation that such stockholder is a holder of stock of the Corporation entitled to vote at such meeting and that such stockholder intends to appear in person or by proxy at the annual meeting to bring such business before the meeting.

In addition, notwithstanding anything in this section of the Corporation's Bylaws to the contrary, a stockholder intending to nominate one or more persons for election as a director at any annual or special meeting of stockholders must comply with Section 13 of these Bylaws for such nominations to be properly brought before such meeting.

No business shall be conducted at the annual meeting of stockholders except business brought before the annual meeting in accordance with the procedures set forth in this section of the Corporation's Bylaws. If the Chairman of an annual meeting determines that business was not properly brought before the annual meeting in accordance with the foregoing procedures, the Chairman shall declare to the meeting that the business was not properly brought before the meeting and such business shall not be conducted at the meeting.

No business shall be conducted at a special meeting of stockholders except for such business as shall have been brought before the meeting pursuant to the Corporation's notice of meeting or such business as is otherwise properly brought before the meeting by or at the direction of the Corporation's Board of Directors.

SECTION 13. At any meeting of stockholders at which directors are to be elected, nominations of persons for election to the Corporation's Board of Directors may be made by or at the direction of the Board of Directors or by any stockholder entitled to vote for the election of directors at such meeting. Any stockholder proposing to make such nominations, if other than at the direction of the Board of Directors, may nominate one or more persons for election as directors only if timely notice of such stockholder's intent is given in proper written form to the Corporation's Secretary at the Corporation's principal executive offices.

To be in proper written form, a stockholder's notice to the Secretary must set forth (a) as to each person whom the stockholder proposes to nominate for election as a director (i) the name, age, business address and residence address of the person, (ii) the principal occupation and employment of the person, (iii) the number of shares of the Corporation's common stock that are owned beneficially or of record by the person and (iv) any other information relating to the person that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Securities Exchange Act of 1934, as amended (the "Exchange Act") (or in any law or statute replacing such section), and the rules and regulations promulgated thereunder; and (b) as to the stockholder giving the notice (i) the name and record address of such stockholder, (ii) the number of shares of the Corporation's common stock that are owned beneficially or of record by such stockholder, (iii) a description of all arrangements or understandings between such stockholder and each proposed nominee and, any other person or persons (including their names) pursuant to which the nomination(s) are to be made by such stockholder, (iv) a representation that such stockholder is a holder of record of stock of the Corporation entitled to vote at the meeting to nominate the person or persons named in its notice, and (v) any other information relating to such stockholder as would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors pursuant to Section 14 of the Exchange Act (or in any law or statute replacing such section) and the rules and regulations promulgated thereunder. Such notice must be accompanies by a written consent, signed by each proposed nominee, to being named as a nominee and to serve as a director of the Corporation if so elected.

No person shall be eligible for election as a director of the Corporation unless nominated in accordance with the procedures set forth in this section of the Corporation's Bylaws. If the Chairman of the meeting determined that a nomination was not made in accordance with the foregoing procedures, the Chairman shall declare to the meeting that the nomination was defective and such defective nomination shall be disregarded and not placed upon the ballot.

SECTION 14. The Chairman of the Board of Directors, or in his absence, the presiding officer, shall have complete authority to establish the rules of conduct to be followed at any meeting of stockholders and to make all decisions concerning procedural issues or questions raised at any meeting of stockholders; provided, however, that the Chairman or presiding officer shall not take any action or make any decision that contravenes applicable state law.

DIRECTORS

SECTION 15. The property and business of this Corporation shall be managed under the direction of the Board of Directors. The Board shall consist of thirteen directors. The Board of Directors shall be divided into three classes, as nearly equal in number as the total number of directors constituting the entire Board permits, with the term of office of one class expiring each year. Each class shall hold office for terms expiring at the third Annual Meeting of Stockholders following the most recent election of such class and when their successors are elected and qualified. Notwithstanding any other provision of the Articles of Incorporation or these Bylaws, any director, or directors, including the entire Board of Directors, may be removed, but only for cause and by the affirmative vote of at least two-thirds of the issued and outstanding stock of the Corporation that is entitled to vote for the elections of directors, and no qualification for the office of director that may be provided for in the Articles of Incorporation or Bylaws shall apply to any director in office at the time such qualification was adopted or to any successor appointed by the remaining directors to fill the term of such director.

SECTION 16. The directors may hold their meetings and have one or more offices and keep the books of the Corporation outside of Utah at such places as they may from time to time determine.

SECTION 17. In addition to the powers and authority by these Bylaws expressly conferred upon them, the Board of Directors may exercise all such powers of the Corporation and do all such lawful acts and things as are not by statute of the State of Utah, or by the Articles of Incorporation, or by these Bylaws directed or required to be exercised or done by the stockholders.

COMMITTEES

SECTION 18. The Board of Directors, by resolution or resolutions passed by a majority of the whole Board, may designate one or more Committees, one of which Committees shall be known as the Executive Committee, and with each Committee to consist of two or more of the directors of the Corporation. To the extent provided in the Articles of Incorporation, these Bylaws, resolutions, or Statements of Responsibility approved by the Board of Directors, the Committees shall have and may exercise the powers conferred upon them by the Board of Directors. All Committees, except the Executive Committee, when so appointed, shall have such name or names as may be stated in these Bylaws or may be determined from time to time by resolutions adopted by the Board of Directors.

SECTION 19. The Committees shall keep regular minutes for their proceedings and report the same to the Board of Directors when required.

COMPENSATION OF DIRECTORS

SECTION 20. Directors, as such, shall not receive any salary for their services, but the Board of Directors by resolution shall fix the fees to be allowed and paid to directors, as such, for their services and provide for the payment of the expenses of the directors incurred by them in performing their duties. Nothing herein contained, however, shall be considered to preclude any director from serving the Corporation in any other capacity and receiving compensation therefor.

SECTION 21. Fees to members of special or standing committees and expenses incurred by them in the performance of their duties, shall also be fixed and allowed by resolution of the Board of Directors.

MEETINGS OF THE BOARD

SECTION 22. The Board of Directors may meet at the Corporation's principal office in Salt Lake County, Utah, or at such other place as may be determined by a majority of the members of the Board.

SECTION 23. Regular meetings of the Board of Directors may be held without notice at such time and place as shall from time to time be determined by the Board.

SECTION 24. Special meetings of the Board of Directors may be called by the Chairman of the Board or the President on one day's notice to each director, with such notice given either in person, by telephone, by electronic dissemination, or by any other means recognized under applicable law to the address listed in the corporate records of the Corporation. Special meetings may be called by the President or Secretary in like manner and on like notice on the written request of two directors.

SECTION 25. At all meetings of the Board of Directors a majority of the directors shall be necessary and sufficient to constitute a quorum for the transaction of business. The act of a majority of the directors present at any meeting at which there is a quorum shall be the act of the Board of Directors, except as may be otherwise specifically provided by statute, by the Articles of Incorporation, or by these Bylaws. Directors may participate in a Board meeting and be counted in the quorum by means of conference telephone or similar communications equipment by which all directors participating in the meeting can hear each other.

SECTION 26. Unless the Articles of Incorporation provide otherwise, any acts required or permitted to be taken by the Board of Directors at a meeting may be taken without a meeting if all the directors take the action, each director signs a written consent describing the action taken, and the consents are filed with the records of the Corporation. Action taken by consent is effective when the last director signs the consent, unless the consent specifies a different effective date. A signed consent has the effect of a meeting vote and may be described as such in any document.

SECTION 27. The officers of the Corporation shall be elected by the directors and shall be as stated in the Articles of Incorporation: a Chairman of the Board of Directors, a President, a Secretary and Treasurer. The Board of Directors may also appoint one or more Vice Presidents and other officers as appropriate. The Secretary and Treasurer may be the same person, and the Chairman of the Board or any Vice President may hold at the same time the office of Secretary or Treasurer.

SECTION 28. The Board of Directors at its first meeting after each annual meeting shall elect a Chairman of the Board of Directors and a President from their own number; and shall also elect a Secretary and a Treasurer who need not be members of the Board of Directors. At such time, the Board of Directors shall also appoint one or more Vice Presidents.

SECTION 29. The Board of Directors may appoint such other officers and agents as it may deem necessary; such officers and agents shall hold their offices for such terms and shall exercise such powers and perform such duties as shall be determined from time to time by the Board.

SECTION 30. The salaries of all officers and agents of the Corporation shall be fixed by the Board of Directors.

SECTION 31. The officers of the Corporation shall hold office until their successors are chosen. Any officer elected or appointed by the Board of Directors may be removed at any time by the affirmative vote of a majority of the whole Board of Directors. If the office of any officer or officers becomes vacant for any reason, the vacancy shall be filled by the affirmative vote of a majority of the whole Board of Directors.

CHAIRMAN OF THE BOARD

SECTION 32. The Chairman of the Board of Directors shall preside at all meetings of the stockholders and of the Board of Directors. He shall have supervision of such matters as may be designated to him by the Board of Directors

PRESIDENT

SECTION 33. Unless another officer is so designated by the Board of Directors, the President shall be the Chief Executive Officer of the Corporation and shall perform the following duties:

(a) In the absence of the Chairman of the Board, the President shall preside at all meetings of the stockholders and directors, have general and active management of the business of the Corporation, and see that all orders and resolutions of the Board of Directors are carried into effect.

(b) The President shall execute bonds, mortgages and other contracts requiring the seal, under the seal of the Corporation.

(c) The President shall have the general powers and duties of supervision and management usually vested in the office of a president of a corporation.

If another officer is designated by the Board of Directors as Chief Executive Officer, the President shall have supervision of such matters as shall be designated to him by the Board of Directors and/or the Chief Executive Officer.

VICE PRESIDENT

SECTION 34. The Vice President shall perform the duties prescribed by the President or the Board of Directors. The Board of Directors may appoint one or more of the Vice Presidents as Senior Vice Presidents and one or more as Executive Vice Presidents.

SECRETARY

SECTION 35. (a) The Secretary shall attend all meetings of the Board of Directors and all meetings of the stockholders and record all votes and the minutes of all proceedings in a book to be kept for that purpose and shall perform like duties for the standing Committees when required. The Secretary shall give or cause to be given notice of all meetings of the stockholders and of the Board of Directors, and shall perform such other duties as may be prescribed by the Board of Directors or President, under whose supervision he shall serve. The Secretary shall keep in safe custody the seal of the Corporation and shall affix the seal to any instrument requiring it and shall attest it.

(b) In the absence or disability of the Secretary, the President may designate an employee to serve as Assistant Secretary to perform the responsibilities prescribed in the Bylaws for the Secretary.

TREASURER

SECTION 36. (a) The Treasurer shall have the custody of the corporate funds and securities and shall keep full and accurate account of receipts and disbursements in moneys and other valuable effects in the name and to the credit of the Corporation in such depositories as may be designated by the Board of Directors. The Treasurer shall disburse the funds of the Corporation as may be ordered by the Board, taking proper vouchers for such disbursements, and shall render to the President and directors at the regular meeting of the Board, or whenever they may require it, an account of all his transactions as Treasurer and of the financial condition of the Corporation.

(b) The President may designate an employee to serve as Assistant Treasurer to assist the Treasurer perform his responsibilities. In the absence or disability of the Treasurer, the Assistant Treasurer shall perform the responsibilities prescribed in the Bylaws for the Treasurer.

VACANCIES

SECTION 37. If the office of any director or directors becomes vacant by reason of the death, resignation, disqualification, removal from office, or otherwise, the remaining directors, though not less than a quorum, shall choose a successor or successors who shall hold office for the remaining portion of the term or terms of the office left vacant until the successor or successors shall have been duly elected, unless sooner displaced.

DUTIES OF OFFICERS MAY BE DELEGATED

SECTION 38. In case of the absence of any officer of the Corporation, or for any other reason that the Board of Directors may deem sufficient, the Board may delegate, for the time being, the power or duties, or any of them, of such officer to any other officer, or to any director, provided a majority of the entire Board concur therein.

CERTIFICATES OF STOCK

SECTION 39. The certificates of stock of the Corporation shall be numbered and shall be entered in the books of the Corporation as they are issued. Every holder of stock shall be entitled to have a certificate signed by or in the name of the Corporation by any two of the following officers: the Chief Executive Officer, Chief Financial Officer, Corporate Secretary or Assistant Secretary, Treasurer or Assistant Treasurer of the Corporation, certifying the number of shares owned by him; provided, however, that where such certificate is signed by a transfer agent or an assistant transfer agent or by a transfer clerk, acting in behalf of the Corporation, and a registrar, the signature of any such Chief Executive Officer, President, Vice President, Treasurer, Assistant Treasurer, Secretary or Assistant Secretary, may be facsimile. In case any officer or officers, who shall have signed or whose facsimile signature or signatures shall have been used on any such certificate or certificates, shall cease to be such officer or officers of such Corporation, whether because of death, resignation or otherwise, before such certificate or certificates shall have been delivered by the Corporation, such certificate or certificates may nevertheless be adopted by the Corporation and be issued and delivered as though the person or persons, who signed such certificate or certificates or whose facsimile signatures shall have been used thereon, had not ceased to be such officer or officers of the Corporation.

TRANSFER OF STOCK

SECTION 40. Transfers of stock shall be made on the books of the Corporation only by the person named in the certificate, or by an attorney, lawfully constituted in writing, and upon surrender of the certificate therefor, and upon the payment of any transfer tax or transfer fees which may be imposed by law or by the Board of Directors.

CLOSING OF TRANSFER BOOKS

SECTION 41. The Board of Directors shall have power to close the stock transfer books of the Corporation for a period not exceeding seventy (70) days preceding the date of any meeting of stockholders, or the date for payment of any dividend, or the date for the allotment of rights, or the date when any change or conversion, or exchange of capital stock shall go into effect, or for a period of not exceeding seventy (70) days in connection with obtaining the consent of stockholders for any purpose. In lieu of closing the stock transfer books, the Board of Directors may fix in advance a date not exceeding seventy (70) days preceding the date of any meeting of stockholders, or the date for the payment of any dividend, or the date for the allotment of rights or the date when any change or conversion, or exchange of capital stock shall go into effect, or a date in connection with obtaining such consent, as a record date for the determination of the stockholders entitled to notice of and to vote at any such meeting, or entitled to receive payment of any such dividend, or to any such allotment of rights, or to exercise the rights in respect of any such change, conversion, or exchange of capital stock. If a record date is fixed by the Board of Directors, only stockholders as of the record date shall be entitled to notice of and to vote at any meeting or to receive payment of dividend or to receive an allotment of rights, notwithstanding any transfer of stock on the books of the Corporation after any such record date.

REGISTERED STOCKHOLDERS

SECTION 42. The Corporation shall be entitled to treat the holder of record of any share or shares of stock as the holder in fact and accordingly shall not be bound to recognize any equitable or other claim to or interest in such share on the part of any person, whether or not it shall have express or other notice thereof, except as expressly provided by the laws of the State of Utah.

LOST CERTIFICATE

SECTION 43. When authorized by the Secretary of the Corporation in writing, the duly appointed stock transfer agency may issue and the duly appointed registrar may register, new or duplicate stock certificates to replace lost, stolen, or destroyed certificates and for the same number of shares as those lost, stolen, or destroyed, upon delivery to the Corporation of an affidavit of loss and indemnity bond or other undertaking acceptable to both the Secretary and legal counsel representing the Corporation's interests.

INSPECTION OF BOOKS

SECTION 44. The Corporation shall maintain permanent records of the minutes of all meetings of its stockholders and Board of Directors; all actions taken by the stockholders or Board of Directors without a meeting; and all actions taken by a Committee of the Board of Directors in place of the Board of Directors on behalf of the Corporation. The Corporation shall also maintain appropriate accounting records.

A stockholder of the Corporation, directly or through an agent or attorney, shall have the limited rights to inspect and copy the Corporation's records as provided under applicable state law and upon complying with the procedures specified under such law.

BANK ACCOUNTS

SECTION 45. All checks, demands for money, or other transactions involving the Corporation's bank accounts shall be signed by such officers or other responsible persons as the Board of Directors may designate. No third party is allowed access to the Corporation's bank accounts without express written authorization by the Board of Directors.

FISCAL YEAR

SECTION 46. The fiscal year shall begin the first day of January in each year.

DIVIDENDS

SECTION 47. Dividends upon the capital stock of the Corporation, subject to the provisions of the Articles of Incorporation and the laws of the State of Utah, if any, may be declared by the Board of Directors at any regular or special meeting, pursuant to law. Dividends may be paid in cash, in property, or in shares of the capital stock.

Before payment of any dividend there may be set aside out of any funds of the Corporation available for dividends such sum or sums as the Board of Directors, in their sole discretion, think proper as a reserve fund to meet contingencies or for equalizing dividends, or for repairing or maintaining property of the Corporation, or for such other purposes as the Board of Directors shall think conducive to the interests of the Corporation.

ANNUAL STATEMENT

SECTION 48. The Chairman of the Board of Directors or any other director so designated by the Board of Directors shall present at each Annual Meeting of Stockholders, and when called for by vote of the stockholders at any special meeting of the stockholders, a full and clear statement of the business and condition of the Corporation.

NOTICE

SECTION 49. Whenever, under the provisions of the Articles of Incorporation or the laws of the State of Utah, notice is required to be given to any director, officer or stockholder, it shall not be construed to mean personal notice, but such notice may be given in writing, by mail or private carrier, by electronic dissemination, or by any other means recognized under applicable state or federal law. If given by mail, the notice shall be mailed on a prepaid basis and shall be addressed to such director, officer, or stockholder, at such address as appears on the books of the Corporation.

Any stockholder, director or officer may waive any notice required to be given under these Bylaws or the Articles of Incorporation.

AMENDMENTS

SECTION 50. These Bylaws may be amended by a majority vote of the directors. These Bylaws may be also amended by the affirmative vote of a majority of the stock issued and outstanding and entitled to vote at any special or regular meeting of the stockholders if notice of the proposed amendment be contained in the minutes of the meeting. Provided, however, that in addition to any vote required by any other provision of these Bylaws, the Articles of Incorporation, or any applicable law, if such amendment is to be adopted solely by the stockholders, the affirmative vote of eighty percent of the issued and outstanding stock of the Corporation that is entitled to vote for the election of directors shall be required for any amendment that deletes or changes Section 15 or this Section 50 of these Bylaws; that restricts or limits the powers of the Board of Directors or any other officers or agents of the Corporation; that vests any powers of the Corporation in any officer or agent other than the Board of Directors, or officers and agents appointed by the Board of Directors, or officers and agents appointed by officers or agents appointed by the Board of Directors; that requires the approval of any stockholders or any other person or entity in order for the Board of Directors or any other corporate officer or agent to take any action; or that changes the quorum requirement for any meeting of the Board of Directors, the vote by which it must act in connection with any matter, the manner of calling or conducting meetings of directors, or the place of such meeting.

INDEMNIFICATION AND LIABILITY INSURANCE

SECTION 51. (a) Voluntary Indemnification. Unless otherwise provided in the Articles of Incorporation, the Corporation shall indemnify any individual made a party to a proceeding because he is or was a director of the Corporation, against liability incurred in the proceeding, but only if the Corporation has authorized the payment in accordance with the applicable statutory provisions [Sections 16-10a-902 and 16-10a-904 of Utah's Revised Business Corporation Act] and a determination has been made in accordance with the procedures set forth in such provision that the director conducted himself in good faith; that he reasonably believed that his conduct, if in his official capacity with the Corporation, was in its best interests and that his conduct, in all other cases, was at least not opposed to the Corporation's best interests; and that he had no reasonable cause to believe his conduct was unlawful in the case of any criminal proceeding.

(b) The Corporation shall not indemnify a director in connection with a proceeding by or in the right of the Corporation in which the director was adjudged liable to the Corporation or in connection with any other proceeding charging improper personal benefit to him, whether or not involving action in his official capacity, in which he was adjudged liable on the basis that personal benefit was improperly received by him.

(c) Indemnification permitted under paragraph (a) in connection with a proceeding by or in the right of the Corporation is limited to reasonable expenses incurred in connection with the proceeding.

(d) If a determination is made, using the procedures set forth in the applicable statutory provision, that the director has satisfied the requirements listed herein and if an authorization of payment is made, using the procedures and standards set forth in the applicable statutory provision, then, unless otherwise provided in the Corporation's Articles of Incorporation, the Corporation shall pay for or reimburse the reasonable expenses incurred by a director who is a party to a proceeding in advance of the final disposition of the proceeding if the director furnishes the Corporation a written affirmation of his good faith belief that he has satisfied the standard of conduct described in this Section, furnishes the Corporation a written undertaking, executed personally or on his behalf, to repay the advance if it is ultimately determined that he did not meet the standard of conduct (which undertaking must be an unlimited general obligation of the director, but need not be secured and may be accepted without reference to financial ability to make repayment); and if a determination is made that the facts then known of those making the determination would not preclude indemnification under this Section.

(e) Mandatory Indemnification. Unless otherwise provided in the Corporation's Articles of Incorporation, the Corporation shall indemnify a director or officer of the Corporation who was wholly successful, on the merits or otherwise, in the defense of any proceeding to which he was a party because he is or was a director or officer of the Corporation against reasonable expenses incurred by him in connection with the proceeding.

(f) Court-Ordered Indemnification. Unless otherwise provided in the Corporation's Articles of Incorporation, a director or officer of the Corporation who is or was a party to a proceeding may apply for indemnification to the court conducting the proceeding or to another court of competent jurisdiction. The court may order indemnification if it determines that the director or officer is entitled to mandatory indemnification as provided in this Section and applicable law, in which case the court shall also order the Corporation to pay the reasonable expenses incurred by the director or officer to obtain court-ordered indemnification. The court may also order indemnification if it determines that the director or officer is fairly and reasonably entitled to indemnification in view of all the relevant circumstances, whether or not the director or officer met the applicable standard of conduct set forth in this Section and applicable law. Any indemnification with respect to any proceeding in which liability has been adjudged in the circumstances described in paragraph (b) above is limited to reasonable expenses.

(g) Unless otherwise provided in the Corporation's Articles of Incorporation, an officer, employee, or agent of the Corporation shall have the same indemnification rights provided to a director by this Section. The Board of Directors may also indemnify and advance expenses to any officer, employee, or agent of the Corporation, to any extent consistent with public policy as determined by the general or specific purpose of the Board of Directors.

(h) Insurance. The Corporation may purchase and maintain liability insurance on behalf of a person who is or was a director, officer, employee, fiduciary, or agent or the Corporation, or who, while serving as a director, officer, employee, fiduciary, or agent of the Corporation, is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee, fiduciary or agent of another foreign or domestic corporation, other person, of an employee benefit plan, or incurred by him in that capacity or arising from his status as a director, officer, employee, fiduciary, or agent, whether or not the Corporation has the power to indemnify him against the same liability under applicable law.

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 September 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.

November 4, 2005

/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 September 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.

November 4, 2005

/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 September 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

November 4, 2005

/s/Keith O. Rattie

Date

Keith O. Rattie

Chairman, President and Chief Executive Officer

November 4, 2005

/s/S. E. Parks

Date

S. E. Parks

Senior Vice President and Chief Financial Officer