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 March 31, 2006

[ ]

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ]

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

On April 30, 2006, 85,552,074 shares of the registrant’s common stock, without par value, were outstanding.

Questar Corporation

Form 10-Q for the Quarter Ended March 31, 2006

TABLE OF CONTENTS

Page No.

Nature of Business

Where You Can Find More Information

Forward-Looking Statements

Glossary of Commonly Used Terms

PART I.

FINANCIAL INFORMATION

Item 1.

Financial Statements

Consolidated Statements of Income for the three months ended

March 31, 2006 and 2005

Condensed Consolidated Balance Sheets at March 31, 2006

and December 31, 2005

Condensed Consolidated Statements of Cash Flows for the three months ended

March 31, 2006 and 2005

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

PART II.

OTHER INFORMATION

Item 1.

Legal Proceedings

Item 2.

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 four major lines of business – gas and oil exploration and production, midstream field services, interstate gas transportation, and retail gas distribution – which are conducted through its three principal subsidiaries. Questar Market Resources, Inc. (Market Resources) is a sub-holding company that 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 gas utility affiliate 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 owns and operates an underground gas-storage reservoir. 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 2005 (PUHCA 2005), because its subsidiary Questar Gas is a gas utility. Questar, however, qualifies for and will file for an exemption and waiver from provisions of the Act applicable to holding companies. PUHCA 2005 supersedes the Public Utility Holding Company Act of 1935 under which Questar qualified for an exemption. 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.

Where You Can Find More Information

Questar and its principal subsidiaries, Market Resources, Questar Pipeline and Questar Gas, each 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. The public may read and copy these reports and any other materials filed with the SEC at its Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549-0213. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC also maintains a website that contains information filed electronically that can be accessed over the Internet at www.sec.gov.

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

Also you may request a copy of filings, other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing or calling Questar, 180 East 100 South Street, P.O. Box 45433, Salt Lake City, Utah 84145-0433 (telephone number (801) 324-5000).

Forward-Looking Statements

This Quarterly Report may contain or incorporate by reference information that includes or is based upon “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. In particular, these include statements relating to future actions, prospective services or products, future performance or results of current and anticipated services or products, exploration efforts, expenses, the outcome of contingencies such as legal proceedings, trends in operations and financial results.

Any or all forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Among factors that could cause actual results to differ materially are:

•

the risk factors discussed in Part I, Item 1A. of the Company’s Annual Report on Form 10-K for the year ended December 31, 2005;

•

general economic conditions, including the performance of financial markets and interest rates;

•

changes in industry trends;

•

changes in laws or regulations; and

•

other factors, most of which are beyond our control.

Questar undertakes no obligation to publicly correct or update the forward-looking statements in this Quarterly Report, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

Glossary of Commonly Used Terms

Billion

bbl

Barrel, which is equal to 42 U.S. gallons and is a common measure of volume of crude oil and other liquid hydrocarbons.

basis

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

Btu

One British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound mass 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 14.7 pounds per square inch).

cfe

Cubic feet of natural gas equivalents

development well

A well drilled into a known producing formation in a previously discovered field.

dewpoint

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.

dthe

Decatherms of natural gas equivalents

equity production

Production at the wellhead attributed to Questar ownership.

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 purchases of reserves in place, 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 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 between the market price for NGL extracted from the gas stream and the market value of the Btu-equivalent volume of natural gas required to replace the extracted liquids.

futures contract

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

gal

U.S. gallon.

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.

infill development drilling

Drilling wells between established producing wells; a drilling program to reduce the spacing between wells in order to increase production and/or recovery of in-place hydrocarbons.

lease operating expenses

The expenses, usually recurring, which are incurred to operate the wells and equipment on a producing lease.

Thousand.

Million.

natural gas equivalents

Oil and NGL volumes are converted to natural gas equivalents using the ratio of one barrel of crude oil, condensate or NGL to 6,000 cubic feet of natural gas.

natural gas liquids (NGL)

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

net revenue interest

A share of production after all burdens, such as royalties and overriding royalties, have been deducted from the working interest. It is the percentage of production that each owner actually receives.

production replacement ratio

The production replacement ratio is calculated by dividing the net proved reserves added through discoveries, positive and negative revisions 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

Reserves that include proved developed producing reserves and proved developed nonproducing reserves. See 17 C.F.R. Section 4-10(a)(3).

proved developed producing reserves

Reserves expected to be recovered from existing completion intervals in existing wells.

proved undeveloped reserves

Reserves expected to be recovered from new wells on proved undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. See 17 C.F.R. Section 4-10(a)(4).

reservoir

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

royalty

An interest in an oil and gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

seismic

An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. (2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.)

wet gas

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

working interest

An interest in an oil and gas lease that gives the owner the right to drill, produce and conduct operating activities on the leased acreage and receive a share of any production.

workover

Operations on a producing well to restore or increase production.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

QUESTAR CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	3 Months Ended
	March 31,
	2006	2005
	(in thousands, except per share amounts)
	(in thousands, except per share amounts)
REVENUES
Market Resources	$415,077	$ 314,338
Questar Pipeline	25,442	17,912
Questar Gas	466,939	343,690
Corporate and other operations	3,915	4,384

TOTAL REVENUES	911,373	680,324

OPERATING EXPENSES
Cost of natural gas and other products sold	462,780	338,805
Operating and maintenance	74,109	56,747
General and administrative	32,318	33,083
Production and other taxes	33,472	26,385
Depreciation, depletion and amortization	72,754	58,825
Exploration	3,299	1,373
Abandonment and impairment of gas,
oil and other properties	1,699	1,405

TOTAL OPERATING EXPENSES	680,431	516,623

OPERATING INCOME	230,942	163,701

Interest and other income	2,447	2,651
Income from unconsolidated affiliates	1,831	1,546
Interest expense	(17,430)	(16,722)

INCOME BEFORE INCOME TAXES	217,790	151,176
Income taxes	80,634	56,005

NET INCOME	$137,156	$ 95,171

EARNINGS PER COMMON SHARE
Basic	$1.61	$1.13
Diluted	1.57	1.10

Weighted average common shares outstanding
Used in basic calculation	85,240	84,417
Used in diluted calculation	87,449	86,728
Dividends per common share	$0.225	$0.215

See notes accompanying the consolidated financial statements

QUESTAR CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31,	December 31,
	2006	2005
	(Unaudited)
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$ 29,147	$ 13,360
Accounts receivable, net	301,986	355,810
Unbilled gas accounts receivable	43,122	86,161
Federal income tax recoverable		11,274
Hedging collateral deposits		5,150
Fair value of hedging contracts	3,525	1,972
Inventories, at lower of average cost or market
Gas and oil storage	34,369	90,718
Materials and supplies	34,551	34,699
Prepaid expenses and other	26,451	30,110
Purchased-gas adjustments	5,734	39,852
Deferred income taxes – current	34,390	86,734
Total current assets	513,275	755,840
Property, plant and equipment	5,703,127	5,527,997
Less accumulated depreciation, depletion and amortization	2,168,171	2,100,455
Net property, plant and equipment	3,534,956	3,427,542
Investment in unconsolidated affiliates	32,322	30,681
Goodwill	71,260	71,260
Regulatory assets	33,857	32,767
Other noncurrent assets, net	34,561	38,983
	$4,220,231	$4,357,073

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt		$ 94,500
Accounts payable and accrued expenses	$ 418,991	526,182
Questar Gas customer-credit balances	5,237	30,829
Fair value of hedging contracts	51,217	222,049
Current portion of long-term debt	200,014	14
Total current liabilities	675,459	873,574
Long-term debt, less current portion	783,202	983,200
Deferred income taxes	669,937	624,187
Asset retirement obligations	80,478	78,123
Pension and post-retirement benefits	60,472	61,049
Fair value of hedging contracts	32,575	99,044
Other long-term liabilities	97,772	88,093

Common shareholders’ equity
Common stock	387,531	383,298
Retained earnings	1,503,704	1,385,783
Accumulated other comprehensive loss	(70,899)	(219,278)
Total common shareholders’ equity	1,820,336	1,549,803
	$4,220,231	$4,357,073

See notes accompanying the consolidated financial statements

QUESTAR CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	3 Months Ended
	March 31,
	2006	2005
	(in thousands)

OPERATING ACTIVITIES
Net income	$ 137,156	$95,171
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	73,977	60,167
Deferred income taxes	7,597	2,105
Share-based compensation	2,220	865
Abandonment and impairment of gas, oil and other properties	1,699	1,405
Income from unconsolidated affiliates	(1,831)	(1,546)
Cash received from unconsolidated affiliates	190	2,114
Net (gain) loss from asset sales	105	(59)
Hedging contract ineffectiveness	22	180
	221,135	160,402
Changes in operating assets and liabilities	100,131	5,139
NET CASH PROVIDED FROM
OPERATING ACTIVITIES	321,266	165,541

INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(196,905)	(128,261)
Other investments		(1,083)
Total capital expenditures	(196,905)	(129,344)
Proceeds from disposition of assets	3,151	1,427
NET CASH USED IN INVESTING ACTIVITIES	(193,754)	(127,917)

FINANCING ACTIVITIES
Common stock issued	2,391	6,288
Common stock repurchased	(2,444)	(2,743)
Long-term debt repaid	(3)	(2)
Decrease in short-term debt	(94,500)	(31,000)
Checks in excess of cash balances		4,348
Dividends paid	(19,235)	(18,196)
Tax benefit from share-based compensation	2,066
NET CASH USED IN FINANCING ACTIVITIES Change in cash and cash equivalents Beginning cash and cash equivalents	(111,725)	(41,305)
	15,787	(3,681)
	13,360	3,681
Ending cash and cash equivalents	$ 29,147	$ -


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, 2005, 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 2005 financial statements to conform with the 2006 presentation.

The results of operations for the three months ended March 31, 2006, are not necessarily indicative of the results that may be expected for the year ending December 31, 2006, due to a variety of factors discussed in the Forward-Looking Statements section of this report. Interim consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. For further information please refer to the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.

Note 2 – 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:

	2006	2005
	(in thousands)

Balance at January 1,	$78,123	$67,288
Accretion	1,225	1,025
Additions	1,441	399
Retirements and properties sold	(311)	(384)
Balance at March 31,	$80,478	$68,328

Wexpro activities are governed by a long-standing agreement with the states of Utah and Wyoming (the Wexpro Agreement). The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is spelled out in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the Public Service Commission of Wyoming (PSCW). Accordingly, Wexpro collects from Questar Gas 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 March 31, 2006, approximately $4.0 million was held in this trust invested primarily in a short-term bond index fund.

Note 3 – 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
	March 31,
	2006	2005
	(in thousands)

Weighted-average basic common shares outstanding	85,240	84,417
Potential number of shares issuable from exercising stock options and from nonvested restricted shares	2,209	2,311
Weighted-average diluted common shares outstanding	87,449	86,728

Questar issued 225,000 and 417,000 shares for the Long-Term Stock Incentive Plan (LTSIP) and other plans in the first three months of 2006 and 2005, respectively.

Note 4 – Share-Based Compensation

Questar issues stock options and restricted shares to certain officers, employees and non-employee directors under its LTSIP. Prior to January 1, 2006, the Company accounted for share-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion (APBO) 25 “Accounting for Stock Issued to Employees” and related interpretations. No compensation cost was recorded for stock options because the exercise price equaled the market price on the date of grant. The granting of restricted shares resulted in recognition of compensation cost. Restricted shares are valued at the grant-date market price and amortized to expense over the vesting period.

The Company implemented SFAS 123R “Share Based Payment,” effective January 1, 2006, and chose the modified prospective phase-in method. The modified prospective phase-in method requires recognition of compensation costs for all share based payments granted, modified or settled after January 1, 2006, as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. Pro forma disclosure of the effect of share-based compensation costs is required by SFAS 123R for prior periods.

As a result of adopting SFAS 123R, the Company’s income before income taxes and net income for the three months ended March 31, 2006, were approximately $0.4 million and $0.3 million lower, respectively, than if the Company had continued to account for share-based compensation under APBO 25. Basic and diluted earnings per share for the three months ended March 31, 2006, were reduced by less than $.01 per share. Share-based compensation associated with unvested restricted shares for the three months ended March 31, 2006 and 2005, amounted to $1.8 million and $0.9 million, respectively. At March 31, 2006, deferred share-based compensation amounted to $17.6 million, of which $4.4 million was attributed to unvested stock options.

SFAS 123R requires the benefits of tax deductions in excess of recognized compensation expense resulting from the exercise of share-based awards be reported as financing cash flow rather than as operating cash flow. For the three months ended March 31, 2006, this requirement reduced net cash provided from operating activities and reduced net cash used in financing activities by $2.1 million.

The following table shows pro forma net income had stock options been expensed in the prior period based on a fair value calculated using the Black-Scholes-Merton model:

	3 Months Ended
	March 31, 2005
	(in thousands)

Net income, as reported	$95,171
Deduct after-tax share-based compensation expense under fair-value based method	(359)
Pro forma net income	$94,812

Earnings per share
Basic, as reported	$ 1.13
Basic, pro forma	1.12
Diluted, as reported	1.10
Diluted, pro forma	1.09

Long-Term Stock Incentive Plan

There were 5,388,966 shares available for future grant at March 31, 2006. The Company granted restricted shares but did not grant stock options in the first quarter of 2006. Transactions involving stock options in the LTSIP in the first quarter of 2006 are summarized below:

	Outstanding Options	Price Range	Weighted- Average Price

Balance at January 1, 2006	3,251,988	$15.00 – $77.14	$27.82
Exercised	(107,640)	15.00 – 35.10	23.09
Balance at March 31, 2006	3,144,348	$15.00 – $77.14	$27.99

Unvested stock options declined by 4,500 to 458,875 in the first quarter of 2006.

Options Outstanding				Options Exercisable		Unvested Options

		Weighted-
	Number	average	Weighted-	Number	Weighted-	Number	Weighted
	outstanding	remaining	average	exercisable	average	unvested at	average
Range of	March 31,	contract life	exercise	March 31,	exercise	March 31,	exercise
Exercise prices	2006	in years	price	2006	price	2006	price

$15.00 – $17.00	476,774	3.7	$15.47	476,774	$15.47
19.13 – 23.95	802,197	5.2	22.71	802,197	22.71
27.11 – 29.71	1,601,438	6.0	27.51	1,392,563	27.56	208,875	$27.19
35.10 – 77.14	263,939	7.1	69.52	13,939	47.26	250,000	70.77
	3,144,348		$27.99	2,685,473	$24.07	458,875	$50.93

Restricted shares generally vest in three to five years. The average weighted life of unvested restricted shares at March 31, 2006 was three years. Transactions involving restricted shares in the LTSIP in the first quarter of 2006 are summarized below:

			Weighted Average
	Shares	Price Range	Price

Balance at January 1, 2006	300,041	$27.11 – $86.03	$40.38
Granted	118,315	68.22 – 81.48	73.50
Forfeited	(120)	28.72	28.72
Distributed	(64,886)	27.11 – 59.38	31.16
Balance at March 31, 2006	353,350	$27.11 – $86.03	$53.16

Note 5 – Financing

Market Resources filed a registration statement with the SEC on April 7, 2006, under the shelf registration process. Once the registration is approved, Market Resources may sell debt securities, as described in the prospectus that was part of the registration statement, in one or more offerings, up to a total of $350 million. Unless otherwise set forth in a prospectus supplement, Market Resources intends to use the net proceeds from the potential sale of the debt securities for general corporate purposes, including repayment of the $200 million aggregate principal amount of its 7% Notes due January 16, 2007, working capital and business expansion.

Note 6 – Operations by Line of Business

Line of business information is presented according to senior management’s basis for evaluating performance including differences in the nature of products, services and regulation. Following is a summary of operations by line of business for the three months ended March 31, 2006 and 2005:

	3 Months Ended
	March 31,
	2006	2005
	(in thousands)

REVENUES FROM UNAFFILIATED CUSTOMERS
Questar E&P	$210,787		$132,497
Wexpro	6,303		5,126
Gas Management	41,248		29,034
Energy Trading	156,739		147,681
Market Resources total	415,077		314,338
Questar Pipeline	25,442		17,912
Questar Gas	466,939		343,690
Corporate and other operations	3,915		4,384
	$911,373		$680,324

REVENUES FROM AFFILIATED CUSTOMERS
Wexpro	$ 38,726		$ 32,984
Gas Management	3,846		3,188
Energy Trading	250,230		142,214
Market Resources total	292,802		178,386
Questar Pipeline	20,566		22,425
Questar Gas	1,577		1,261
Corporate and other operations	428		602
	$315,373		$202,674

OPERATING INCOME
Questar E&P	$118,687		$ 63,442
Wexpro	18,217		15,878
Gas Management	14,668		12,943
Energy Trading	3,311		2,455
Market Resources total	154,883		94,718
Questar Pipeline	23,930		18,357
Questar Gas	51,507		49,951
Corporate and other operations	622		675
	$230,942		$163,701

NET INCOME
Questar E&P	$ 70,490		$ 36,251
Wexpro	11,985		10,182
Gas Management	9,738		8,808
Energy Trading	2,452		1,380
Market Resources total	94,665		56,621
Questar Pipeline	11,439		8,339
Questar Gas	29,364		28,712
Corporate and other operations	1,688		1,499
	$137,156		$ 95,171

Note 7 – Employee Benefits

Questar has defined-benefit pension and postretirement medical and life insurance plans covering the majority of its employees. Questar is subject to and 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 seeks to fund the qualified retirement plan approximately equal to the yearly expense. Currently the qualified pension expense estimate for 2006 is $17.5 million. Components of qualified pension expense included in the determination of interim net income are listed below:

	3 Months Ended
	March 31,
Qualified Pension Expense	2006	2005
	(in thousands)

Service cost	$ 2,565	$ 2,265
Interest cost	5,448	5,135
Expected return on plan assets	(5,184)	(4,962)
Prior service and other costs	298	320
Recognized net-actuarial loss	1,251	736
Amortization of early-retirement costs		725
Qualified pension expense	$ 4,378	$ 4,219

The Company currently estimates a $4.7 million expense for postretirement benefits other than pensions in 2006 before $0.8 million for accretion of a regulatory liability. Expense components are listed below:

	3 Months Ended March 31,
	3 Months Ended March 31,
Postretirement Benefits Other Than	2006	2005
Pensions	(in thousands)

Service cost	$ 233	$ 219
Interest cost	1,153	1,310
Expected return on plan assets	(732)	(730)
Amortization of transition obligation	470	470
Amortization of losses	50	119
Accretion of regulatory liability	200	200
Postretirement benefit expense	$1,374	$1,588

Note 8 – 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
	March 31,
	2006	2005
	(in thousands)

Net income	$137,156	$ 95,171
Other comprehensive income (loss)
Unrealized gain (loss) on energy hedging transactions	238,876	(186,154)
Income taxes	(90,497)	70,771
Net other comprehensive income (loss)	148,379	(115,383)
Total comprehensive income (loss)	$285,535	($ 20,212)

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

	March 31,	December 31,
	2006	2005	Change
	(in thousands)

Unrealized loss on energy-hedging transactions	($49,723)	($198,102)	$148,379
Additional pension liability	(21,176)	(21,176)
Accumulated other comprehensive loss	($70,899)	($219,278)	$148,379

Note 9 – Recent Accounting Development

On March 31, 2006, the Financial Accounting Standards Board (FASB) issued an exposure draft reconsidering the accounting for pensions and other postretirement benefits. The exposure draft segregates the accounting changes into phases. Changes in the balance sheet are expected from the first phase of this project. The proposed changes, if approved, will cause companies to record the over or under funded status of defined benefit plans on the balance sheet. The over or under funded pension position will be measured by the difference in the fair value of plan assets and the projected benefit obligation. The projected benefit obligation includes future salary changes. The over or under funded postretirement benefit position will be measured by the difference in the fair value of plan assets and the accumulated benefit obligation. The second phase will address asset and liability measurement issues and will affect the income statement. Elimination of unrecognized actuarial gains or losses is among the considered changes. The comment period of this exposure draft ends May 31, 2006. Any first phase changes may be in effect for year-end 2006 reporting. The Company has not measured the impact of these proposed changes as described in the exposure draft.

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

Summary

Questar reported net income for the first quarter of 2006 of $137.2 million or $1.57 per diluted share compared to $95.2 million or $1.10 per share for the first quarter of 2005. Following are comparisons of net income by line of business:

	3 Months Ended
	March 31,		% Change
	2006	2005	% Change
	(in millions, except per share amounts)
Net income
Questar E&P	$70.5	$36.3	94%
Wexpro	12.0	10.2	18
Gas Management	9.7	8.8	10
Energy Trading and other	2.5	1.3	92
Market Resources Total	94.7	56.6	67

Questar Pipeline	11.4	8.3	37
Questar Gas	29.4	28.7	2
Corporate and other operations	1.7	1.6	6
QUESTAR CORPORATION TOTAL	$137.2	$95.2	44%
Diluted shares outstanding (average)	87.4	86.7
Earnings per diluted share	$1.57	$1.10	43%

Market Resources reported net income of $94.7 million in the first quarter of 2006, up 67% from the first quarter of 2005. The increase was driven by higher natural gas production and higher realized prices for natural gas, oil and NGL, higher gas processing volumes and margins and a 16% increase in Wexpro’s investment base. Gas Management reported a 34% increase in first quarter 2006 NGL sales volumes resulting primarily from increased throughput at a gas processing plant in western Wyoming acquired in the first quarter of 2005.

Questar Pipeline net income increased 37% in the first quarter of 2006 compared to the 2005 period as a result of an expanded number of firm-transportation contracts and higher liquids revenues.

Questar Gas net income in the first quarter of 2006 was 2% higher than the year earlier period. The 2006 results included the settlement of a long-standing regulatory dispute with the State of Utah. Total margin from gas sales increased 4% due to a 4.2% growth in the number of customers offset by a 2% decrease in temperature-adjusted gas usage per customer.

Results of Operations

Market Resources Consolidated Results

Market Resources net income for the first quarter of 2006 was $94.7 million compared with $56.6 million for the year earlier period, a 67% increase. Operating income increased $60.2 million, or 64%, in the quarter to quarter 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 processing margins at Gas Management.

Following is a summary of Market Resources financial and operating results for the first quarter of 2006 compared with the first quarter of 2005:

	3 Months Ended
	March 31,
	2006	2005
	(in thousands)
OPERATING INCOME
Revenues
Natural gas sales	$178,841	$108,601
Oil and NGL sales	36,716	26,948
Cost-of-service gas operations	39,575	33,633
Energy marketing	167,243	149,654
Gas gathering, processing and other	45,139	33,586
Total revenues	467,514	352,422
Operating expenses
Energy purchases	163,149	146,533
Operating and maintenance	45,387	31,659
General and administrative	16,573	14,370
Production and other taxes	27,925	21,244
Depreciation, depletion and amortization	53,022	39,859
Exploration	3,299	1,373
Abandonment and impairment of gas, oil and other properties	1,699	1,405
Wexpro Agreement – oil-income sharing	1,577	1,261
Total operating expenses	312,631	257,704
Operating income	$154,883	$ 94,718

OPERATING STATISTICS
Questar E&P production volumes
Natural gas (MMcf)	28,556	22,839
Oil and NGL (Mbbl)	623	583
Total production (Bcfe)	32.3	26.3
Average daily production (MMcfe)	359	293
Questar E&P average realized price, net to the well (including hedges)
Natural gas (per Mcf)	$6.26	$4.76
Oil and NGL (per bbl)	$50.42	$38.74
Wexpro investment base at March 31, net
of depreciation and deferred income taxes (millions)	$214.5	$185.7
Natural gas gathering volumes (in thousands of MMBtu)
For unaffiliated customers	32,650	32,535
For Questar Gas	10,563	11,256
For other affiliated customers	18,016	15,846
Total gathering	61,229	59,637
Gathering revenue (per MMBtu)	$0.29	$0.26
Natural gas and oil marketing volumes (Mdthe)
For unaffiliated customers	29,532	28,910
For affiliated customers	25,562	22,551
Total marketing	55,094	51,461

Questar E&P

Questar E&P reported net income of $70.5 million in the first quarter, up 94% from $36.3 million in the 2005 quarter. The increase was driven by a combination of higher realized natural gas, oil and NGL prices and increased gas, oil and NGL production volumes.

Questar E&P reported production volumes increased to 32.3 Bcfe in the first quarter of 2006, a 23% increase compared to the year-earlier period. The 2006 quarter included a 0.7 Bcfe gas-imbalance settlement. Excluding the imbalance settlement, Questar E&P production grew 20% compared to the year earlier period. Prior year production was negatively impacted by weather-related completion and workover delays on Uinta Basin and western Midcontinent properties and delays caused by seasonal access restrictions on Rockies Legacy properties during the first quarter. 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 production growth in the first three months of 2005.

On an energy-equivalent basis, natural gas comprised approximately 88% of Questar E&P production for the first three months of 2006. A comparison of natural gas-equivalent production by region is shown in the following table:

	3 Months Ended
	March 31,
	2006	2005
	(in Bcfe)
Rocky Mountains
Pinedale Anticline	9.7	7.5
Uinta Basin	6.2	5.7
Rockies Legacy	5.1*	4.1
Subtotal – Rocky Mountains	21.0	17.3
Midcontinent	11.3	9.0
Total Questar E&P production	32.3	26.3

*Includes 0.7 Bcfe gas-imbalance settlement.

Questar E&P production from the Pinedale Anticline in western Wyoming grew 29% from the year-earlier quarter and comprised 30% of Questar E&P total production in the 2006 period. 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 grew production 9% compared to the first quarter of 2005. Uinta Basin production in the year ago period was negatively impacted by weather-related delays and other production constraints.

Production from Questar E&P Rocky Mountain “Legacy” properties increased 24% in the 2006 quarter, including the 0.7 Bcfe gas-imbalance settlement. Excluding the imbalance settlement, Legacy production volumes grew 7% in the current quarter compared to the year-earlier period, driven by the company’s emerging gas play in the Vermillion Basin. Legacy assets include all Questar E&P Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin.

In the Midcontinent, production grew 26% to 11.3 Bcfe, driven by ongoing development drilling in the Elm Grove field in northwestern Louisiana. The company is continuing its infill-development of the Elm Grove properties. Questar E&P midcontinent production also benefited from completion of a new exploratory well in the Arkoma Basin of eastern Oklahoma. The well has produced 0.8 Bcfe and has averaged 6 MMcfe per day since coming on line on December 14, 2005. Questar E&P has a 96.2% working interest and an 84.2% net revenue interest in the well before payout of a 200% nonconsent penalty and a 69.5% working interest and a 60.8% net revenue interest after payout.

Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. For the first three months of 2006, the weighted average realized natural gas price for Questar E&P (including the effects of hedging) was $6.26 per Mcf compared to $4.76 per Mcf for the same period in 2005, a 32% increase. Realized oil and NGL prices for the first three months of 2006 averaged $50.42 per bbl, compared with $38.74 per bbl during the prior year period, a 30% increase. A regional comparison of average realized prices, including hedges, is shown in the following table:

	3 Months Ended
	March 31,
	2006	2005
Natural gas (per Mcf)
Rocky Mountains	$ 6.01	$ 4.56
Midcontinent	6.72	5.12
Volume-weighted average	$ 6.26	$ 4.76
Oil and NGL (per bbl)
Rocky Mountains	$48.73	$39.47
Midcontinent	54.31	37.01
Volume-weighted average	$50.42	$38.74

Approximately 66% of Questar E&P gas production in the first quarter of 2006 was hedged or pre-sold. Hedging reduced gas revenues $16.0 million during the first quarter of 2006. For the current quarter, approximately 77% of Questar E&P’s oil production was hedged. Oil hedges reduced revenues $3.7 million during the first quarter of 2006.

Questar may hedge up to 100 percent of forecasted production from proved reserves to lock in acceptable returns on invested capital and to protect returns, cash flow and net income from a decline in commodity prices. During the first quarter of 2006, Questar E&P continued to take advantage of high natural gas and oil prices to hedge additional production in 2006, 2007 and 2008. Natural gas and oil hedges as of March 31, 2006, are summarized in Part I, Item 3 of this quarterly report.

Questar E&P controllable production costs (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense and allocated-interest expense) per Mcfe of production increased 5% compared to the first quarter of 2005. Questar E&P controllable production costs are summarized in the following table:

	3 Months Ended
	March 31,
	2006	2005
	(per Mcfe)

Depreciation, depletion and amortization	$1.28	$1.13
Lease operating expense	0.54	0.55
General and administrative expense	0.34	0.34
Allocated-interest expense	0.19	0.21
Total controllable production costs	$2.35	$2.23

Depreciation, depletion and amortization expense rose 13% in the first quarter to $1.28 due to higher costs for drilling, completion and related services, increased cost of steel casing, other tubulars and wellhead equipment, and the ongoing depletion of older, lower-cost reserves. Per Mcfe lease operating expense decreased slightly as increased costs of materials and consumables were offset by higher production volumes. Similarly, interest expense per Mcfe of production decreased in the current quarter as total interest expense remained about constant. For the first quarter of 2006, general and administrative expenses remained flat at $0.34 per Mcfe compared to the same period in 2005.

Production taxes were $0.51 per Mcfe in 2006 compared to $0.46 per Mcfe in the prior year quarter. Increased production taxes were driven by higher gas, oil and NGL sales prices. Most production taxes are based on a fixed percentage of gas, oil, and NGL sales prices.

Exploration expense increased $1.9 million in the first quarter 2006 compared to the 2005 period. The increase was due to $1.6 million of exploratory dry hole expense in the Midcontinent. Abandonment and impairment expense increased $0.3 million for the first quarter 2006.

Pinedale Anticline Drilling Activity

As of March 31, 2006, Market Resources (both Questar E&P and Wexpro) operated and had working interest in 144 producing wells on the Pinedale Anticline compared to 106 at the end of the first quarter of 2005. Of the 144 producing wells, Questar E&P has working interests in 124 wells, overriding royalty interests only in an additional 19 Wexpro-operated wells, and no interest in one well operated by Wexpro. Wexpro has working interests in 57 of the 144 producing wells. Market Resources expects to complete 45 to 48 Lance Pool wells (combined Lance and Mesaverde formations) on its Pinedale acreage during 2006.

In 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.

Uinta Basin

During the first three months of 2006, the company drilled or participated in 14 Wasatch and Upper Mesaverde gas wells, one horizontal Green River Formation oil well, and one deeper Blackhawk and Mancos formation gas well on its core acreage block. Questar E&P completed its first deep well designed to test the Mancos and Dakota formations. The well, in which Questar E&P has a 77.5% working interest, has averaged 1.4 MMcfe per day during its first 41 days online. A second deep well is at total depth waiting on completion.

Questar E&P recently reached total depth on the Wolf Flat 14C-29-15-19 well, the second 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. Completion operations are underway. Questar E&P has a 75% working interest in the well.

Rockies Legacy

In the Vermillion Basin on the southwest Wyoming-northwest Colorado border, Market Resources continues to evaluate the potential of several formations under the company’s 146,000 net leasehold acres. As of March 31, 2006, the company had recompleted two older wells, drilled and completed six new wells, and was drilling two wells. The targets are the Baxter Shale, which extends across a 3,000-3,500 foot gross interval from about 9,500 feet deep to about 13,000 feet deep on most of the company’s leasehold in the basin, and the deeper Frontier and Dakota tight-sand formations at depths down to 15,000 feet.

Midcontinent

During the first quarter the company continued its one-rig infill-development project in the Elm Grove field in northwest Louisiana as it drilled or participated in nine new wells. On March 31, 2006, Questar E&P acquired interests in 48 producing wells in nine units in the Elm Grove field. The acquisition will provide Questar E&P initial or additional working interest in approximately 75 undrilled locations. The company plans to participate in about 17 additional Elm Grove wells during the remainder of 2006. In the Hartshorne coalbed-methane project in the Arkoma Basin of eastern Oklahoma the company drilled or participated in six new wells in the first three months of 2006 and anticipates participating in an additional three wells during the remainder of 2006.

Wexpro

For the first quarter of 2006 Wexpro’s net income was $12.0 million, compared with $10.2 million for the same period in 2005, an 18% 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% to 20% 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 at March 31, 2006, increased 16% to $214.5 million up $28.8 million over the year earlier period. Wexpro’s net income also benefited from 26% higher realized oil and NGL prices versus the first quarter of 2005.

Gas Management

Gas Management net income increased 10% to $9.7 million in the first quarter of 2006 from $8.8 million in the 2005 period. Gross keep-whole processing margins (revenue from the sale of extracted NGL less the cost of natural gas to replace the Btu-equivalent of extracted NGL volumes.), grew 12% from $6.8 million in the first three months of 2005 to $7.6 million in 2006. NGL sales volumes in the first quarter of 2006 increased 34% versus the year earlier period, primarily as a result of increased throughput at a gas processing plant in western Wyoming acquired in the first quarter of 2005. Gathering volumes increased 1.6 million MMBtu to 61.2 million MMBtu in the first three months of 2006 due primarily to expanding Pinedale production and new projects serving third parties in the Uinta Basin. Total gathering margins decreased primarily due to start-up costs associated with the Pinedale liquids-gathering and transportation facilities.

To reduce processing margin risk, Gas Management has restructured a number of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. A keep-whole contract protects producers from frac spread risk while fee-based contracts eliminate commodity-price risk for the plant owner. To further reduce margin volatility associated with keep-whole contracts, Gas Management began managing NGL price risk in 2004 by using forward-sales contracts. In the first three months of 2006 keep-whole contracts benefited from a 26% increase in realized NGL sales prices versus the prior-year period. Fee-based contracts were impacted by a $0.06 decrease in the rate charged per MMBtu processed in the three month comparable periods. Forward sales contracts increased NGL revenues by $1.7 million in 2006.

Income before tax from Gas Management’s 50% interest in Rendezvous increased to $1.7 million for the first three months of 2006 versus $1.5 million for 2005, a 12% increase. Income 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.

Energy Trading

Energy Trading’s net income for the first quarter of 2006 was $2.5 million compared to $1.3 million in 2005. Gross margins for gas and oil marketing (gross revenues less costs for gas and oil purchases, transportation and gas storage), increased to $4.1 million for the first three months of 2006 versus $3.1 million a year ago, a 31% increase. The increase in gross margin was due primarily to a 23% higher unit margin, a 7% increase in volumes and increased storage activity 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 first quarter of 2006 compared with the first quarter of 2005:

	3 Months Ended
	March 31,
	2006	2005
	(in thousands)
OPERATING INCOME
Revenues
Transportation	$ 30,071	$ 26,586
Storage	9,557	9,576
Gas processing	1,432	1,782
Liquid revenues and other	4,948	2,393
Total revenues	46,008	40,337
Operating expenses
Operating and maintenance	7,550	7,072
General and administrative	4,927	6,062
Depreciation and amortization	7,912	7,254
Other taxes	1,689	1,592
Total operating expenses	22,078	21,980
Operating income	$ 23,930	$ 18,357

OPERATING STATISTICS
Natural gas transportation volumes (in Mdth)
For unaffiliated customers	62,717	55,602
For Questar Gas	40,857	43,739
For other affiliated customers	3,746	1,976
Total transportation	107,320	101,317
Transportation revenue (per dth)	$0.28	$0.26
Firm-daily transportation demand at March 31 (Mdth)	2,155	1,625

Questar Pipeline net income was $11.4 million in the first quarter of 2006 compared with $8.3 million in the first quarter of 2005. Revenues increased in the 2006 quarter due to new transportation contracts and higher liquid revenues.

Revenues

Gas transportation volumes increased in the first quarter of 2006 over the prior year quarter due to new transportation contracts. Following is a summary of major changes in Questar Pipeline’s revenues for the three months ended March 31, 2006, compared with the same period of 2005:

	3 Months Ended March 31, 2006 Compared with 2005
	(in thousands)
Transportation
New transportation contracts	$4,450
Expiration of transportation contracts	(564)
Other transportation	(401)
Storage	(19)
Gas processing	(350)
Liquid revenues and other
Change in liquid revenues	1,480
Change in gathering revenue	165
Park and loan revenue	984
Other	(74)
Increase	$5,671

As of March 31, 2006, Questar Pipeline had firm-transportation contracts of 2,155 Mdth per day compared with 1,625 Mdth per day as of March 31, 2005. Questar Pipeline has expanded its transportation system in response to growing regional natural gas production and transportation demand. In the second quarter of 2005, Questar Pipeline began operating a lateral to an electric generation power plant with a capacity of 190 Mdth per day. In the fourth quarter of 2005, Questar Pipeline completed an expansion of its southern system, which added capacity of 102 Mdth per day. On January 1, 2006, Questar Pipeline subsidiary, Questar Overthrust Pipeline, placed an interconnection with Kern River Pipeline in service, which added capacity of 220 Mdth per day. Each of these expansion projects was fully subscribed with long-term contracts.

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 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.

Liquid revenues increased in the first quarter of 2006 over the first quarter of 2005 due to a 63% increase in volumes of liquids sold and a 43% increase in sales price. Liquid revenues were also impacted by the fuel-gas reimbursement percentage proceedings as discussed below.

Revenues from park and loan services increased in the first quarter of 2006 over the first quarter of 2005 due to increased demand. Questar Pipeline shares 75% of its park and loan revenues with customers once it has received revenues equal to the cost of service. Any additional revenues received in 2006 will be shared with customers.

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 dewpoint facilities at the Kastler plant in northeastern Utah. Questar Pipeline accrued a potential liability equal to any liquid revenues from the dewpoint plant. Through June 30, 2005, Questar Pipeline had reduced revenues by $5.4 million as a credit to customers, including $0.5 million recorded in the first quarter 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 volumes and 0.15% of prior period amortization of volumes. If actual ongoing volumes are less than the 1.95%, the difference will be shared equally with customers beginning January 2006. The FGRP rate for 2006 is 1.84% plus the 0.15% amortization of prior volumes.

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.

Expenses

Operating, maintenance, general and administrative expenses decreased $0.7 million in the first quarter of 2006 compared with the first quarter of 2005. Most of this decrease is due to a change in fuel gas procedures at the company’s Price, Utah processing plant. Beginning in July 2005 customers at the plant began supplying their own fuel gas. Operating, maintenance, general and administrative expenses per decatherm transported declined from $0.130 in the first quarter of 2005 to $0.116 in the first quarter of 2006.

Depreciation expense increased 9% in the first quarter of 2006 over the first quarter of 2005 due to investment in pipeline expansions.

Clay Basin Storage

Questar Pipeline conducts periodic pressure tests on its Clay Basin storage facility. Beginning with a test in April 2002, the company noted a discrepancy between the book volumes of cushion gas at Clay Basin and the volumes implied by pressure data. Questar Pipeline retained a reservoir consultant to model the reservoir and determine the size and cause of the discrepancy. The company conducted additional pressure tests in April 2004, October 2004, April 2005, October 2005 and April 2006 to validate the model. Test results for the April 2006 test have not yet been evaluated.

The reservoir model indicates from 0 to 3.8 Bcf of gas may be missing from Clay Basin, with the most likely amount of 3.2 Bcf. The gas loss is due to a combination of cumulative imprecision inherent in natural gas measurement devices and reservoir heterogeneity that impacts storage reservoir performance. There is no indication that the reservoir is leaking. The Clay Basin reservoir is functioning as expected to meet customer requirements.

Questar Pipeline has proposed to the FERC that the loss of gas be recorded as a reduction of native gas remaining in the reservoir which would not impact Questar Pipeline net income. Alternatively, if the FERC requires Questar Pipeline to adjust recoverable cushion gas, earnings could be reduced by about $3 million after taxes.

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 first quarter of 2006 compared with the first quarter of 2005:

	3 Months Ended
	March 31,
	2006	2005
	(in thousands)
OPERATING INCOME
Revenues
Residential and commercial sales	$441,493	$322,046
Industrial sales	9,640	10,407
Transportation for industrial customers	1,611	1,607
Other	15,772	10,891
Total revenues	468,516	344,951
Cost of natural gas sold	371,142	251,597
Margin	97,374	93,354
Operating expenses
Operating and maintenance	21,074	18,025
General and administrative	9,613	10,886
Depreciation and amortization	11,572	11,306
Other taxes	3,608	3,186
Total operating expenses	45,867	43,403
Operating income	$51,507	$49,951

OPERATING STATISTICS
Natural gas volumes (in Mdth)
Residential and commercial sales	42,265	39,919
Industrial sales	1,151	1,703
Transportation for industrial customers	8,485	8,655
Total deliveries	51,901	50,277
Natural gas revenue (per dth)
Residential and commercial sales	$10.45	$8.07
Industrial sales	8.37	6.11
Transportation for industrial customers	0.19	0.19
Heating degree days – warmer than normal	2%	5%
Average temperature adjusted usage
per customer (dth)	48.9	49.9
Customers at March 31,	834,252	800,523

Questar Gas net income was $29.4 million in the first quarter of 2006 compared with $28.7 million in the first quarter of 2005. First quarter results benefited from settlement of a long-standing regulatory dispute with the State of Utah. Excluding the settlement, Questar Gas net income was about flat with the first quarter of 2005. The impact of customer growth was partially offset by declining usage per customer.

Margin Analysis

Questar Gas margin (revenues less gas costs) increased $4.0 million in the first quarter of 2006 compared to the first quarter of 2005. Following is a summary of major changes in Questar Gas margin:

	3 Months Ended March 31, 2006 Compared with 2005
	(in thousands)

New customers	$ 3,134
Decreased usage per customer	(1,585)
Gas processing revenues collected from customers	1,417
Interest on past-due receivables	290
Recovery of bad debt gas costs	1,439
Other – includes customers shifting between rate schedules	(675)
Increase	$ 4,020

Residential and commercial sales volumes increased 6% in the first quarter of 2006 over the first quarter of 2005 as a result of increased customers. These increases were partially offset by decreased usage per customer. At March 31, 2006, Questar Gas was serving 834,252 customers, a 4.2% increase over the prior year. Housing construction in Utah and Wyoming remained strong, driven by population growth. Usage per customer, adjusted for normal temperatures, was down 2% in the first quarter of 2006 compared with 2005. 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 2% warmer than normal in the first quarter of 2006 compared with 5% warmer than normal in the first quarter of 2005. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations.

Industrial deliveries (including sales and transportation) declined 7% in the first quarter of 2006 compared with 2005 primarily driven by lower power-generation requirements in the current period.

As discussed below, Questar Gas received rate coverage for gas processing costs in the first quarter of 2006 amounting to $1.4 million.

The increase in bad-debt costs as discussed below has been partially offset with recovery of the gas-cost portion of bad debt costs through the gas balance account. This increased the first quarter 2006 margin by $1.4 million.

Expenses

Cost of natural gas sold increased 48% in the first quarter of 2006 compared with 2005 due primarily to increased gas purchase cost per dth. Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the Public Service Commission of Utah (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 March 31, 2006, Questar Gas had a $5.7 million balance in the purchased-gas adjustment account representing gas costs incurred but not yet recovered from customers. Rates in Utah effective in April 2006 were 26% higher than a year earlier.

Operating, maintenance, general and administrative expenses increased $1.8 million or 6% in the first quarter of 2006 compared with 2005. Increased bad debt costs accounted for $1.5 million of the increase. As noted earlier, the gas-cost portion of bad debts is recovered through the gas balance account.

Depreciation expense increased 2% in the first quarter of 2006 compared with 2005 due to plant additions from customer growth.

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 requested ongoing rate coverage for gas processing costs in its pass-through filings. 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 submitted a stipulation to the PSCU to resolve issues related to the recovery of gas processing costs. The PSCU held a hearing on October 20, 2005, and issued an order on January 6, 2006, approving the stipulation beginning on February 1, 2005. The stipulation provides for the recovery of 90% of the non fuel cost of service for processing and 100% of the fuel costs up to 360 Mdth per year. Half of the third-party processing revenues are shared with customers after the first $0.4 million. In the fourth quarter of 2005 Questar Gas reduced expenses for recovery of gas costs by $4.9 million for the period from February 1, 2005 to December 31, 2005. A request to the PSCU for rehearing of this issue was denied. The individuals who filed this request have appealed the issue to the Utah Supreme Court.

Rate Matters

The PSCU has scheduled hearings in May and June, 2006 to consider Questar Gas' proposed Conservation Enabling Tariff (CET). If the PSCU approves the CET as proposed, Questar Gas revenues would no longer be sensitive to changes in average temperature-adjusted usage per customer. In return for the adoption of the CET, Questar Gas would promote gas-use conservation. Questar Gas rates would also be adjusted to reflect lower depreciation rates, rate coverage for pipeline integrity costs, an increased level of long-term debt in its capital structure, and possibly other changes.

Consolidated Results after Operating Income

Income 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 $1.7 million in the 2006 quarter versus $1.5 million in 2005. Rendezvous gathering volumes increased 10% in the first quarter of 2006 compared to the year earlier period.

Interest expense

Interest expense rose in the first quarter of 2006 because of higher interest rates.

Interest and Other Income

Interest and other income decreased in the first quarter of 2006 compared to the same period of 2005. Questar Pipeline capitalized $0.2 million of carrying costs on a construction project in first quarter of 2005.

Income taxes

The effective combined federal and state income tax rate was 37.0% in the 2006 and 2005 quarters.

Liquidity and Capital Resources

Operating Activities

	3 Months Ended
	March 31,
	2006	2005
	(in thousands)

Net income	$137,156	$ 95,171
Noncash adjustments to net income	83,979	65,231
Changes in operating assets and liabilities	100,131	5,139
Net cash provided from operating activities	$321,266	$165,541

Net cash provided from operating activities increased 94% in the first quarter of 2006 compared to the same quarter of 2005 because of higher net income and lower hedging collateral deposits. Hedging collateral deposits declined to zero at March 31, 2006, compared with $83.4 million at March 31, 2005, 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, lower commodity prices and the settlement of hedge contracts.

Investing Activities

A comparison of capital expenditures for the first three months of 2006 and 2005 plus a forecast for calendar year 2006 are presented below:

			Forecast
	3 Months Ended		12 Months Ended
	March 31,		December 31,
	2006	2005	2006

Market Resources	$172,150	$102,169	$490,400
Questar Pipeline	1,463	8,274	122,400
Questar Gas	23,214	18,650	99,100
Corporate and other operations	78	251	800
Total	$196,905	$129,344	$712,700

Market Resources expanded Rockies, Uinta Basin and Midcontinent drilling programs represented the majority of the increase in capital expenditures for the first three months of 2006 compared to the 2005 period.

Financing Activities

Net cash provided from operating activities was sufficient to fund net capital expenditures, repay $94.5 million of short-term debt and pay dividends in the first quarter of 2006. Total debt, including the current portion of long-term debt, was 35% of total capital at March 31, 2006. Questar Gas borrowed $50 million under a five-year term loan in the fourth quarter of 2005 and used the proceeds to repay short-term debt.

The Company had $500 million of short-term lines of credit available at March 31, 2006, but no amount borrowed.

Moody’s completed a ratings update of Questar and its subsidiaries and issued a stable outlook. In its report dated April 11, 2006, Moody’s affirmed Questar’s P-2 commercial paper rating, Market Resources Baa3 senior unsecured long-term debt rating and A-2 ratings for senior unsecured long-term debt issued by Questar Pipeline and Questar Gas.

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, a portion of Energy Trading gas- and oil-marketing transactions and 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 reserves when prices meet earnings and cash flow objectives. 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 the first quarters of 2006 or 2005.

As of March 31, 2006, approximately 57.2 bcf of forecast gas production for the remainder of 2006 was hedged at an estimated average price of $6.21 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 with no borrowings outstanding at March 31, 2006.

A summary of Market Resources hedging positions for equity production as of March 31, 2006, is shown below. Prices are net to the well. Currently all hedges are fixed-price swaps with creditworthy counterparties, allowing Market Resources to realize 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.

	Rocky			Rocky
Time Periods	Mountains	Midcontinent	Total	Mountains	Midcontinent	Total
				Estimated
	Gas (in Bcf)			Average price per Mcf, net to the well
2006
Second quarter	12.9	6.0	18.9	$5.93	$6.81	$6.21
Second half	26.1	12.2	38.3	5.93	6.81	6.21
9 months	39.0	18.2	57.2	5.93	6.81	6.21

2007
First half	18.1	10.1	28.2	$6.92	$7.82	$7.24
Second half	18.4	10.3	28.7	6.92	7.82	7.24
12 months	36.5	20.4	56.9	6.92	7.82	7.24

2008
First half	6.8	3.3	10.1	$6.55	$7.23	$6.78
Second half	6.9	3.4	10.3	6.55	7.23	6.78
12 months	13.7	6.7	20.4	6.55	7.23	6.78

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

2006
Second quarter	310	100	410	$47.77	$59.89	$50.73
Second half	626	202	828	47.77	59.89	50.73
9 months	936	302	1,238	47.77	59.89	50.73

2007
First half	525	199	724	$56.85	$57.83	$57.12
Second half	534	202	736	56.85	57.83	57.12
12 months	1,059	401	1,460	56.85	57.83	57.12

2008
First half	109	73	182	$64.23	$65.30	$64.66
Second half	111	73	184	64.23	65.30	64.66
12 months	220	146	366	64.23	65.30	64.66

Market Resources held gas-price hedging contracts covering the price exposure for about 174.6 million MMBtu of gas, 3.1 MMbbl of oil and 30.9 million gallons of NGL as of March 31, 2006. A year earlier Market Resources’ hedging contracts covered 174.9 million MMBtu of natural gas, 2.6 MMbbl of oil and 10.1 million gallons of NGL.

The following table summarizes changes in the fair value of hedging contracts from December 31, 2005 to March 31, 2006:

			(in thousands)

Net fair value of gas- and oil-hedging contracts outstanding at December 31, 2005			($319,121)
Contracts realized or otherwise settled			52,905
Increase in gas and oil prices on futures markets			184,310
Contracts added since December 31, 2005			1,639
Net fair value of gas- and oil-hedging contracts outstanding at March 31, 2006			($80,267)

A table of the net fair value of gas-hedging contracts as of March 31, 2006, i s shown below. About 59% 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 March 31, 2007	($47,692)
Contracts maturing between April 1, 2007 and March 31, 2008	(30,352)
Contracts maturing between April 1, 2008 and March 31, 2009	(2,223)
Net fair value of gas- and oil-hedging contracts at March 31, 2006	($80,267)

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 March 31,
	2006	2005
	(in millions)

Mark-to-market valuation – liability	($80.3)	($253.8)
Value if market prices of gas and oil decline by 10%	45.0	(145.5)
Value if market prices of gas and oil increase by 10%	($205.6)	(338.1)

Interest-Rate Risk Management

As of March 31, 2006, Questar had $983.2 million of fixed-rate long-term debt including $200 million classified in current liabilities and no variable rate 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.

Beaver Gas Pipeline System. On April 23, 2006, the Oklahoma Court of Civil Appeals affirmed the dismissal of a lawsuit filed by Kaiser-Francis Oil Company against Questar E&P in Kaiser-Francis Oil v. Anadarko Petroleum Corp., et al., Case No. CJ-2003-66518 (Dist. Ct. Okla.) seeking indemnification for a settlement paid by Kaiser-Francis in a related case. Kaiser-Francis was a co-defendant of Questar E&P in a prior Oklahoma case, Bridenstine v. Kaiser-Francis Oil Co. The original lawsuit was a class action alleging improper royalty payments for wells connected to the Beaver Gas Pipeline System in western Oklahoma. Questar E&P and Anadarko settled out of the class action lawsuit in December 2000. Kaiser-Francis chose not to settle and was assessed damages, including punitive damages, by a jury. Kaiser-Francis ultimately settled for $82.5 million, plus interest. Kaiser-Francis’ current lawsuit alleges that Questar E&P and Anadarko were obligated by express and implied indemnities to pay for a portion of the damages assessed in the jury trial and for its legal-defense costs. In dismissing the lawsuit for failure to state a claim, the district judge noted that the jury determined that Kaiser-Francis was involved in a conspiracy to commit fraud and was therefore barred by a doctrine similar to “unclean hands” from seeking indemnity for the judgment.

Pinedale Unit Net Profits Interest. On March 23, 2006, Questar E&P and Wexpro filed a declaratory judgment action Questar Exploration & Production Company and Wexpro Company v. Doyle Hartman, et al., (Case No. 2006-6839) in the District Court of Sublette County, Wyoming to determine the interest of Doyle Hartman and other alleged stakeholders (collectively the Hartman parties) who claim a 5% net profits interest (NPI) in Pinedale leasehold interests of Questar E&P, Wexpro and others. The dispute relates to the scope of the NPI, created by a 1954 contract, to which the defendants purport to be successors. By its terms the NPI relates to the former Pinedale Unit, a federal exploratory unit, and is computed based on revenues and expenses from “unit operations.” The complaint alleges that the Pinedale Unit contracted significantly after the 1954 NPI contract was executed and therefore the NPI, so far as Questar E&P and Wexpro are concerned, is limited to a 1,000 acre remnant of the contracted Pinedale Unit.

On March 31, 2006, Questar E&P and Wexpro were served with a complaint in litigation filed by the Hartman parties. The action, styled Doyle Hartman, et al v. Questar Exploration and Production Company, Wexpro Company, Ultra Resources, Inc., Shell Rocky Mountain Production LLC, Encana Oil and Gas (USA) Inc., Lance Oil and Gas Company, SWEPI LP, Williams Production Rocky Mountain Co., Gemini Resources, Inc., and Arrowhead Resources (U.S. A.) Ltd. (Case No. 2006-6843), was filed in the District Court of Sublette County, Wyoming. The complaint seeks declaratory judgment that the NPI affects leases committed to the original Pinedale Unit regardless of whether the leases and lands have been eliminated from the Pinedale Unit by contraction of that unit. The complaint also seeks an accounting, damages for breach of contract, breach of royalty payment obligations, slander of title, breach of the duty of good faith and fair dealing and conversion.

Environmental Matters. In 2004, the Environmental Protection Agency (EPA) issued two separate compliance orders alleging that Gas Management did not comply with regulatory requirements adopted to enforce the federal Clean Air Act. Both orders involved facilities in the Uinta Basin of eastern Utah that were purchased by Questar E&P in mid-2001. Gas Management is currently operating the facilities and filing necessary reports in compliance with regulatory requirements. In settlement discussions with EPA during April 2006, EPA broadened its allegations to include additional potential violations of the Clean Air Act for the referenced facilities. Other Gas Management facilities in the Uinta Basin have been added to the civil penalty discussions with the EPA, with similar allegations of Clean Air Act violations. EPA is also making allegations that Questar and its affiliates failed to provide EPA with complete and accurate information regarding its emission sources within “Indian country” of the Uinta Basin. These potential violations may result in civil penalties of an unknown and undetermined amount but in excess of $100,000.

Questar Pipeline received a Notice of Violation from the Colorado Department of Public Health and Environment, Air Pollution Control Division (APCD) dated February 3, 2005, concerning its operation of a tank battery in Rio Blanco County, Colorado. Specifically, the Colorado agency alleged that Questar Pipeline violated applicable environmental regulations by failing to obtain the necessary permits and complying with the best available control technology. Questar Pipeline has reached a settlement with APCD to resolve the Notice of Violation by entering into a Consent Order dated effective April 17, 2006, requiring the payment of $319,000 and undertaking a supplemental environmental project with an economic value of $340,000.

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 March 31, 2006:

	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
January 1, 2006 – January 31, 2006	909	$82.76	-	-

February 1, 2006 – February 28, 2006	27,332	74.52	-	-

March 1, 2006 – March 31, 2006	5,996	71.12	-	-

Total	34,237	$74.15	-	-

*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 and any shar es of restricted stock forfeited when failing to satisfy vesting conditions.

Item 6. Exhibits

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

Exhibit No.

Exhibit

31.1.

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

31.2.

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

32.

Certification signed by Keith O. Rattie and S. E. Parks, Questar’s Chairman, President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

QUESTAR CORPORATION

(Registrant)

May 5, 2006

/s/Keith O. Rattie

Date

Keith O. Rattie, Chairman of the Board,

President and Chief Executive Officer

May 5, 2006

/s/S. E. Parks

Date

S. E. Parks, Senior Vice President and

Chief Financial Officer

Exhibits List

Exhibits

31.1.

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

31.2.

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

32.

Exhibit 31.1.

CERTIFICATION

I, Keith O. Rattie, certify that:

I have reviewed this quarterly report of Questar Corporation on Form 10-Q for the period ending March 31, 2006;

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.

May 5, 2006

/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 March 31, 2006;

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.

May 5, 2006

/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 March 31, 2006, 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

May 5, 2006

/s/Keith O. Rattie

Date

Keith O. Rattie

Chairman, President and Chief Executive Officer

May 5, 2006

/s/S. E. Parks

Date

S. E. Parks

Senior Vice President and Chief Financial Officer