UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

[X]

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

For the quarter ended June 30, 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 or 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 July 31, 2006, 85,702,781 shares of the registrant’s common stock, without par value, were outstanding.

#

Questar Corporation

Form 10-Q for the Quarter Ended June 30, 2006

TABLE OF CONTENTS

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 (Unaudited)

Consolidated Statements of Income for the three and six months ended

   June 30, 2006 and 2005

Condensed Consolidated Balance Sheets as of June 30, 2006

   and December 31, 2005

Condensed Consolidated Statements of Cash Flows for the six months ended

   June 30, 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 4.

Submission of Matters to a Vote of Security Holders

Item 5.

Other Information

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 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

B

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.

cf

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

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 value 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.

M

Thousand.

MM

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		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
	(in thousands, except per share amounts)
REVENUES
Market Resources	$384,110	$344,896	$  799,187	$  659,234
Questar Pipeline	24,912	19,087	50,354	36,999
Questar Gas	181,853	151,043	648,792	494,733
Corporate and other operations	5,355	5,183	9,270	9,567
TOTAL REVENUES	596,230	520,209	1,507,603	1,200,533
OPERATING EXPENSES
Cost of natural gas and other products sold	220,854	225,577	683,634	564,382
Operating and maintenance	68,244	63,312	142,353	120,059
General and administrative	30,292	29,647	62,610	62,730
Production and other taxes	25,864	26,250	59,336	52,635
Depreciation, depletion and amortization	73,269	59,807	146,023	118,632
Exploration	10,101	5,476	13,400	6,849
Abandonment and impairment of gas,
oil and other properties	1,843	1,493	3,542	2,898
TOTAL OPERATING EXPENSES	430,467	411,562	1,110,898	928,185
OPERATING INCOME	165,763	108,647	396,705	272,348
Interest and other income	3,710	2,922	6,157	5,573
Income from unconsolidated affiliates	1,701	1,675	3,532	3,221
Unrealized mark-to-market loss on basis swaps, net	(5,614)		(5,614)
Loss on early extinguishment of debt	(1,746)		(1,746)
Interest expense	(19,762)	(16,643)	(37,192)	(33,365)
INCOME BEFORE INCOME TAXES	144,052	96,601	361,842	247,777
Income taxes	53,690	35,874	134,324	91,879
NET INCOME	$  90,362	$  60,727	$  227,518	$  155,898
EARNINGS PER COMMON SHARE
Basic	$      1.06	$      0.71	$        2.67	$       1.84
Diluted	1.03	0.70	2.60	1.79
Weighted average common shares outstanding
Used in basic calculation	85,352	84,679	85,301	84,546
Used in diluted calculation	87,492	87,051	87,475	86,888
Dividends per common share	$     0.235	$     0.225	$        0.46	$       0.44

See notes accompanying the consolidated financial statements

#

QUESTAR CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

			June 30,	December 31,
			2006	2005
			(in thousands)
ASSETS
Current assets
Cash and cash equivalents			$     73,760	$    13,360
Accounts receivable, net			226,971	355,810
Unbilled gas accounts receivable			13,048	86,161
Federal income tax recoverable				11,274
Derivative collateral deposits				5,150
Fair value of derivative contracts			4,482	1,972
Inventories, at lower of average cost or market
Gas and oil storage			52,369	90,718
Materials and supplies			42,216	34,699
Prepaid expenses and other			24,076	30,110
Purchased-gas adjustments				39,852
Deferred income taxes – current			36,901	86,734
Total current assets			473,823	755,840
Property, plant and equipment			5,822,528	5,527,997
Less accumulated depreciation,    depletion and amortization			2,183,778	2,100,455
Net property, plant and equipment			3,638,750	3,427,542
Investment in unconsolidated affiliates			33,915	30,681
Goodwill			71,260	71,260
Regulatory assets			32,470	32,767
Other noncurrent assets, net			39,803	38,983
			$4,290,021	$4,357,073
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt				$     94,500
Accounts payable and accrued expenses			$   313,750	526,196
Questar Gas customer-credit balances			8,401	30,829
Fair value of derivative contracts			28,548	222,049
Purchased-gas adjustments			28,498
Total current liabilities			379,197	873,574
Long-term debt			1,032,374	983,200
Deferred income taxes			699,515	624,187
Asset retirement obligations			83,368	78,123
Pension and post-retirement benefits			57,318	61,049
Fair value of derivative contracts			17,270	99,044
Other long-term liabilities			96,990	88,093
Common shareholders’ equity
Common stock			393,386	383,298
Retained earnings			1,573,947	1,385,783
Accumulated other comprehensive loss			(43,344)	(219,278)
Total common shareholders’ equity			1,923,989	1,549,803
			$4,290,021	$4,357,073

See notes accompanying the consolidated financial statements

#

QUESTAR CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

		6 Months Ended
		June 30,
		2006	2005
		(in thousands)
OPERATING ACTIVITIES
Net income		$227,518	$ 155,898
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization		150,432	122,445
Deferred income taxes		17,813	20,555
Share-based compensation		4,444	2,026
Abandonment and impairment of gas, oil and other properties		3,542	2,898
Income from unconsolidated affiliates		(3,532)	(3,221)
Distributed income from unconsolidated affiliates		2,823	2,217
Net gain from asset sales		(181)	(3,594)
Unrealized mark-to-market loss on basis swaps, net		5,614
Loss on early extinguishment of debt		1,746
Ineffective portion of fixed-price swaps		(259)	328
		409,960	299,552
Changes in operating assets and liabilities		93,129	26,794
NET CASH PROVIDED FROM
OPERATING ACTIVITIES		503,089	326,346
INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment		(359,926)	(281,278)
Other investments		(2,525)	(1,842)
Total capital expenditures		(362,451)	(283,120)
Proceeds from disposition of assets		2,771	16,380
NET CASH USED IN INVESTING ACTIVITIES		(359,680)	(266,740)
FINANCING ACTIVITIES
Common stock issued		4,524	10,946
Common stock repurchased		(3,130)	(5,282)
Long-term debt issued, net of issue costs		246,953
Long-term debt repaid		(200,006)	(5)
Early extinguishment of debt costs		(1,746)
Decrease in short-term debt		(94,500)	(31,000)
Dividends		(39,354)	(37,289)
Excess tax benefits from share-based compensation		4,250
NET CASH USED IN FINANCING ACTIVITIES   Change in cash and cash equivalents   Beginning cash and cash equivalents		(83,009)	(62,630)
		60,400	(3,024)
		13,360	3,681
Ending cash and cash equivalents		$  73,760	$       657
See notes accompanying the consolidated financial statements

#

NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Basis of Presentation of Interim Consolidated Financial Statements

The accompanying unaudited consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) for interim financial information and pursuant to the rules and regulations of the SEC. The 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. All significant intercompany accounts and transactions were eliminated in consolidation. Interim consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005. Certain reclassifications were made to prior period financial statements to conform with the current presentation.

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. The results of operations for the six months ended June 30, 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.

Note 2 – Earnings Per Share (EPS)

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

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
		(in thousands)
Weighted-average basic common shares outstanding	85,352	84,679	85,301	84,546
Potential number of shares issuable from exercising    stock options and from nonvested restricted shares	2,140	2,372	2,174	2,342
Weighted-average diluted common shares    outstanding	87,492	87,051	87,475	86,888

Questar issued 372,000 and 581,000 shares for the Long-Term Stock Incentive Plan (LTSIP) and other plans in the first six months of 2006 and 2005, respectively.

Note 3 – 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 issued 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. As a result of adopting SFAS 123R, the Company’s income before income taxes and net income for the six months ended June 30, 2006, were approximately $0.9 million and $0.6 million lower, respectively, than if the Company had continued to account for share-based compensation under APBO 25. Share-based compensation reduced basic and diluted earnings per share for the six months ended June 30, 2006, by $0.03 per share. Share-based compensation associated with unvested restricted shares for the six months ended June 30, 2006 and 2005, amounted to $3.6 million and $2.0 million, respectively. At June 30, 2006, deferred share-based compensation amounted to $17.4 million, of which $4.0 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 in the financing activities section of the Condensed Consolidated Statements of Cash Flow. For the six months ended June 30, 2006, this requirement reduced net cash provided from operating activities and reduced net cash used in financing activities by $4.3 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	6 Months Ended
	June 30, 2005	June 30, 2005
	(in thousands)
Net income, as reported	$60,727	$155,898
Deduct after-tax share-based compensation    expense under fair-value based method	(360)	(719)
Pro forma net income	$60,367	$155,179
Earnings per share
Basic, as reported	$0.71	$1.84
Basic, pro forma	0.71	1.84
Diluted, as reported	0.70	1.79
Diluted, pro forma	0.69	1.79

Long-Term Stock Incentive Plan

There were 5,361,366 shares available for future grant at June 30, 2006. The Company granted restricted shares but did not grant stock options in the first half of 2006. Transactions involving stock options in the LTSIP in the first half 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	(237,019)	15.00 –   35.10	23.14
Balance at June 30, 2006	3,014,969	$15.00 – $77.14	$28.19

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

Options Outstanding				Options Exercisable		Unvested Options
Range of exercise prices	Number outstanding at June 30, 2006	Weighted-average remaining term in years	Weighted-average exercise price	Number exercisable at June 30, 2006	Weighted-average exercise price	Number unvested at June 30, 2006	Weighted average exercise price
$15.00 – $17.00	453,772	3.4	$15.45	453,772	$15.45
19.13 –   23.95	743,024	5.0	22.74	743,024	22.74
27.11 –   29.71	1,554,234	5.8	27.50	1,345,359	27.55	208,875	$27.19
35.10 –   77.14	263,939	6.8	69.52	13,939	47.26	250,000	70.77
	3,014,969	5.3	$28.19	2,556,094	$24.11	458,875	$50.93

Restricted shares generally vest in three to five years. The average weighted life of unvested restricted shares at June 30, 2006, was three years. Transactions involving restricted shares in the LTSIP in the first half 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	147,165	68.23 –   81.48	73.04
Distributed	(71,476)	27.11 –   68.22	33.07
Forfeited	(1,370)	28.72 –   75.99	57.66
Balance at June 30, 2006	374,360	$27.11 – $86.03	$54.55

Note 4 – 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 six months ended June 30, 2006 and 2005:

#

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
		(in thousands)
REVENUES FROM UNAFFILIATED CUSTOMERS
Questar E&P	$198,385	$137,350	$   409,172	$   269,847
Wexpro	3,669	3,425	9,972	8,551
Gas Management	40,485	33,148	81,733	62,182
Energy Trading and other	141,571	170,973	298,310	318,654
Market Resources total	384,110	344,896	799,187	659,234
Questar Pipeline	24,912	19,087	50,354	36,999
Questar Gas	181,853	151,043	648,792	494,733
Corporate and other operations	5,355	5,183	9,270	9,567
	$596,230	$520,209	$1,507,603	$1,200,533
REVENUES FROM AFFILIATED CUSTOMERS
Wexpro	$  36,517	$  33,204	$    75,243	$     66,188
Gas Management	3,632	3,400	7,478	6,588
Energy Trading and other	158,948	131,541	409,178	273,755
Market Resources total	199,097	168,145	491,899	346,531
Questar Pipeline	19,827	21,517	40,393	43,942
Questar Gas	1,237	1,370	2,814	2,631
Corporate and other operations	408	473	836	1,075
	$220,569	$191,505	$   535,942	$   394,179
OPERATING INCOME (LOSS)
Questar E&P	$104,206	$  60,518	$   222,893	$   123,960
Wexpro	18,294	15,871	36,511	31,749
Gas Management	15,104	13,115	29,772	26,058
Energy Trading and other	784	1,559	4,095	4,014
Market Resources total	138,388	91,063	293,271	185,781
Questar Pipeline	21,729	17,346	45,659	35,703
Questar Gas	2,735	(2,122)	54,242	47,829
Corporate and other operations	2,911	2,360	3,533	3,035
	$165,763	$108,647	$   396,705	$   272,348
NET INCOME (LOSS)
Questar E&P	$  56,100	$  34,426	$   126,590	$     70,677
Wexpro	11,957	10,495	23,942	20,677
Gas Management	10,186	8,962	19,924	17,770
Energy Trading and other	1,042	878	3,494	2,258
Market Resources total	79,285	54,761	173,950	111,382
Questar Pipeline	9,884	7,593	21,323	15,932
Questar Gas	(693)	(3,446)	28,671	25,266
Corporate and other operations	1,886	1,819	3,574	3,318
	$  90,362	$  60,727	$   227,518	$   155,898

#

Note 5 – 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 $17.8 million. Components of qualified pension expense included in the determination of interim net income are listed below:

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
		(in thousands)
Service cost	$ 2,565	$ 2,103	$  5,130	$ 4,369
Interest cost	5,448	5,205	10,896	10,340
Expected return on plan assets	(5,184)	(4,932)	(10,368)	(9,893)
Prior service and other costs	298	320	596	639
Recognized net-actuarial loss	1,251	1,019	2,502	1,754
Amortization of early-retirement costs		725		1,450
Qualified pension expense	$ 4,378	$ 4,440	$  8,756	$ 8,659

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		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
		(in thousands)
Service cost	$   233	$   181	$   466	$    400
Interest cost	1,153	990	2,306	2,300
Expected return on plan assets	(732)	(748)	(1,464)	(1,478)
Amortization of transition obligation	470	469	940	939
Amortization of (gains) losses	50	(78)	100	41
Accretion of regulatory liability	200	200	400	400
Postretirement benefits expense	$1,374	$1,014	$2,748	$2,602

Note 6 – 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		2,461	2,061
Additions		3,395	1,326
Retirements and properties sold		(611)	(511)
Balance at June 30,		$83,368	$70,164

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 June 30, 2006, approximately $4.2 million was held in this trust invested primarily in a short-term bond index fund.

Note 7 – Capitalized Exploratory Well Costs

The Company capitalizes exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial, in which case the well costs are immediately charged to exploration expense. Net changes in capitalized exploratory well costs for the first half of 2006 are as follows and exclude amounts that were capitalized and subsequently expensed in the period:

	2006
	(in thousands)
Balance at January 1,	$16,514
Additions to capitalized exploratory well costs pending the
determination of proved reserves	8,077
Reclassifications to property, plant and equipment after the
determination of proved reserves	(331)
Capitalized exploratory well costs charged to expense	(1,448)
Balance at June 30,	$22,812

The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

	June 30,	December 31,
	2006	2005
	(in thousands)
Capitalized exploratory well costs that have been capitalized
one year or less	$22,812	$16,514
Capitalized exploratory well costs that have been capitalized
longer than one year
Balance at end of period	$22,812	$16,514

Note 8 – Financing

On May 11, 2006, Market Resources sold $250 million principal amount of 6.05% Notes due 2016. Net proceeds of $247 million were used for general corporate purposes including the June 14, 2006, early extinguishment of its $200 million of 7% Notes due 2007. Market Resources recorded a $1.7 million pre-tax charge related to the early extinguishment of the 7% Notes.

Note 9 – Questar Gas Rate Reduction

In response to the rising cost of buying gas for its customers, Questar Gas in December 2005 proposed a comprehensive three-year pilot program to promote energy conservation. The Division of Public Utilities and Utah Clean Energy (a public-interest group working to promote energy efficiency) joined Questar Gas in the request. The key feature of the proposal is a “conservation enabling tariff” (CET). The company’s current rate structure does not provide an incentive for the company to increase conservation efforts because energy conservation reduces company revenues and profits. Under the proposed CET, Questar Gas revenues would be decoupled from the volume of gas used by customers. Questar Gas would then work with customers to find ways to reduce natural gas consumption.

Questar Gas and most other parties agreed to a settlement of issues other than the CET that had been proposed in this case. Effective June 1, 2006, the Public Service Commission of Utah (PSCU) approved a settlement ordering Questar Gas to reduce the nongas portion of customer rates by $9.7 million to reflect a reduction in depreciation rates, a change in capital structure, and recovery of pipeline integrity costs.

The reduction of depreciation rates resulted from a study ordered in the last general rate case and is estimated to be $8.5 million per year. The following changes were made to the depreciation rates: asset lives were increased for most asset classes; cost of asset retirement was included in the depreciation rate as negative salvage; low value general plant assets were changed to a vintage amortization rather than specific asset accounting; and accumulated depreciation was adjusted to conform to the new rates over the next ten years. The average annual depreciation rate declined from 3.9% to 3.0%. These new depreciation rates were adopted in June 2006.

Note 10 – 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 certain gas- and oil-price hedging arrangements. 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 or if the derivative is determined to be ineffective. A summary of comprehensive income is shown below:

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
		(in thousands)
Net income	$  90,362	$  60,727	$227,518	$155,898
Other comprehensive income (loss)
Net unrealized gain (loss) on hedging contracts	44,406	38,336	283,282	(147,818)
Income taxes	(16,851)	(14,541)	(107,348)	56,230
Net other comprehensive income (loss)	27,555	23,795	175,934	(91,588)
Total comprehensive income	$117,917	$ 84,522	$403,452	$  64,310

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

		June 30,	December 31,
		2006	2005	Change
		(in thousands)
Net unrealized gain (loss) on hedging contracts		($22,168)	($198,102)	$175,934
Additional pension liability		(21,176)	(21,176)
Accumulated other comprehensive loss		($43,344)	($219,278)	$175,934

Note 11 – Recent Accounting Development

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (FIN 48). The interpretation applies to all tax positions related to income taxes subject to FASB Statement No. 109 “Accounting for Income Taxes.” FIN 48 clarifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. FIN 48 is effective January 1, 2007. The Company is evaluating the effect, if any, that FIN 48 will have on its financial statements.

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

Summary

Questar grew net income 49% in the second quarter of 2006 to $90.4 million or $1.03 per diluted share, compared to $60.7 million or $0.70 per diluted share, for the second quarter of 2005. Second quarter 2006 results included a $3.5 million after-tax charge or $0.04 per diluted share for an unrealized mark-to-market loss on natural gas basis swaps and a $1.1 million after-tax charge or $0.01 per diluted share related to early extinguishment of $200 million of Market Resources 7% notes. Net income growth was driven by higher natural gas production and higher realized prices for natural gas, oil and NGL.

For the first half of 2006, Questar net income was $227.5 million, or $2.60 per diluted share compared to $155.9 million or $1.79 per diluted share for the 2005 period, a 46% increase. Following are comparisons of net income by line of business:

	3 Months Ended			6 Months Ended
	June 30,		%	June 30,			%
	2006	2005	Change	2006		2005	Change
	(in millions, except per share amounts)
Net income (loss)
Market Resources
Questar E&P	$56.1	$34.4	63%		$126.6	$ 70.7	79%
Wexpro	12.0	10.5	14	23.9		20.7	15
Gas Management	10.2	9.0	13	19.9		17.8	12
Energy Trading and other	1.0	0.9	11	3.5		2.2	59
Market Resources total	79.3	54.8	45	173.9		111.4	56
Questar Pipeline	9.9	7.6	30	21.3		15.9	34
Questar Gas	(0.7)	(3.4)	79	28.7		25.3	13
Corporate and other operations	1.9	1.7	12		3.6	3.3	9
Questar Corporation total	$90.4	$60.7	49%		$227.5	$155.9	46%
Earnings per diluted share	$1.03	$0.70		$  2.60		$  1.79
Average diluted shares	87.5	87.1		87.5		86.9

Market Resources net income was 45% higher in the second quarter of 2006 and 56% higher for the first half of 2006 compared to the same periods 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 an increased investment base for Wexpro.

Questar Pipeline net income grew 30% in the second quarter and 34% in the first half of 2006 compared to the 2005 periods as a result of additional firm-transportation contracts supporting recent system expansions and higher NGL revenues.

Questar Gas seasonal net loss narrowed by $2.7 million in the second quarter of 2006 and first half 2006 net income increased 13% compared with the 2005 periods. The improved 2006 results were from higher margins from customer growth and the recovery of gas-processing costs in 2006 that were not recognized in 2005 results until the fourth quarter.

Results of Operations

Market Resources

Market Resources, which conducts natural gas and oil exploration, development and production, gas gathering and processing, wholesale gas and oil marketing and gas storage reported net income for the second quarter of 2006 was $79.3 million compared with $54.8 million for the year earlier period, a 45% increase. Net income for the first six months of 2006 totaled $173.9 million versus $111.4 million for the same period in 2005, a 56% increase. Operating income increased $47.3 million, or 52%, in the quarter to quarter comparison, and $107.5 million, or 58%, in the six month comparison due primarily to increased natural gas production and higher realized prices at Questar E&P, an increased investment base at Wexpro and increased gas-processing plant margins at Gas Management.

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

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
		(in thousands)
OPERATING INCOME
Revenues
Natural gas sales	$165,233	$112,918	$344,074	$221,519
Oil and NGL sales	36,250	27,976	72,966	54,924
Cost-of-service gas operations	34,885	32,020	74,460	65,653
Energy marketing	142,021	171,256	309,264	320,910
Gas gathering, processing and other	45,885	36,467	91,024	70,053
Total revenues	424,274	380,637	891,788	733,059
Operating expenses
Energy purchases	140,274	168,696	303,423	315,229
Operating and maintenance	42,203	36,991	87,590	68,650
General and administrative	15,486	13,335	32,059	27,705
Production and other taxes	20,129	20,962	48,054	42,206
Depreciation, depletion and amortization	54,613	41,257	107,635	81,116
Exploration	10,101	5,476	13,400	6,849
Abandonment and impairment of gas,     oil and other properties	1,843	1,493	3,542	2,898
Wexpro Agreement – oil-income sharing	1,237	1,364	2,814	2,625
Total operating expenses	285,886	289,574	598,517	547,278
Operating income	$138,388	$  91,063	$293,271	$185,781
OPERATING STATISTICS
Questar E&P production volumes
Natural gas (MMcf)	27,561	23,410	56,117	46,249
Oil and NGL (Mbbl)	620	586	1,243	1,169
Total production (Bcfe)	31.3	26.9	63.6	53.3
Average daily production (MMcfe)	344	296	351	294
Questar E&P average realized price, net to the well (including hedges)
Natural gas (per Mcf)	$    6.00	$     4.82	$    6.13	$       4.79
Oil and NGL (per bbl)	$  50.11	$   40.02	$  50.27	$     39.38
Wexpro investment base at June 30, net
of depreciation and deferred income      taxes (millions)	$  220.1	$   188.0
Natural gas gathering volumes (in thousands      of MMBtu)
For unaffiliated customers	35,784	33,539	68,434	66,074
For Questar Gas	9,679	11,226	20,242	22,482
For other affiliated customers	16,977	14,416	34,993	30,262
Total gathering	62,440	59,181	123,669	118,818
Gathering revenue (per MMBtu)	$    0.29	$     0.25	$     0.29	$      0.25
Natural gas and oil marketing volumes (Mdthe)
For unaffiliated customers	25,755	26,347	55,287	55,256
For affiliated customers	24,316	22,095	49,878	44,647
Total marketing	50,071	48,442	105,165	99,903

Questar E&P

Questar E&P, a Market Resources subsidiary that conducts natural gas and oil exploration, development and production, reported net income of $56.1 million in the second quarter, up 63% from $34.4 million in the 2005 quarter. Net income for the first six months of 2006 was $126.6 million versus $70.7 million for the same period of 2005, a 79% increase. The increases were driven by a combination of higher realized natural gas, oil and NGL prices and increased gas, oil and NGL production volumes.

Questar E&P reported production volumes increased to 31.3 Bcfe in the second quarter of 2006, a 16% increase compared to the year-earlier period. Production for the first six months of 2006 was 63.6 Bcfe versus 53.3 Bcfe for the 2005 period, a 19% increase. On an energy-equivalent basis, natural gas comprised approximately 88% of Questar E&P production for the first six months of 2006. A comparison of natural gas-equivalent production by region is shown in the following table:

	3 Months Ended					6 Months Ended
	June 30,			%		June 30,			%
	2006*	2005		Change		2006**		2005	Change
	(Bcfe)					(Bcfe)
Pinedale Anticline	8.2		6.5	26%		17.9	14.1		27%
Uinta Basin	6.2		6.9	(10)		12.4	12.6		(2)
Rockies Legacy	4.9		4.1	20		10.0	8.1		23
Subtotal – Rocky Mountains	19.3		17.5	10		40.3	34.8		16
Midcontinent	12.0		9.4	28		23.3	18.5		26
Total Questar E&P	31.3		26.9	16%		63.6	53.3		19%

*  Includes 0.3 Bcf related to a working interest adjustment in Rockies Legacy. Without the one-time

    adjustment, total Questar E&P production grew 15%.

**Includes 0.7 Bcfe related to settlement of an imbalance and 0.3 Bcf related to a working interest

    adjustment in Rockies Legacy. Without the one-time adjustments, total Questar E&P production grew

    17%.

Questar E&P production from the Pinedale Anticline in western Wyoming grew 27% to 17.9 Bcfe in the first six months of 2006 and comprised 28% 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 that restrict the company’s ability to drill and complete wells during the period. As a result, Pinedale second quarter 2006 production was 1.5 Bcfe lower than first quarter 2006.

In the Uinta Basin of eastern Utah, Questar E&P production decreased 2% to 12.4 Bcfe in the first six months of 2006 compared to a year ago. Second quarter production was 10% lower than the same period a year ago and equal to that of first quarter 2006.

Production from Questar E&P Rocky Mountain “Legacy” properties increased 23% to 10.0 Bcfe in the first six months of 2006 compared to a year ago. Excluding one-time adjustments, Legacy production for the first six months of 2006 was 9.0 Bcfe, an increase of 11% over the 2005 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 23.3 Bcfe in the first six months of 2006, driven by ongoing infill-development drilling in the Elm Grove field in northwestern Louisiana. Questar E&P midcontinent production also benefited from the December 2005 completion of an exploratory well in the Arkoma Basin of eastern Oklahoma. The well has produced 1.3 Bcfe and has averaged 5.9 MMcfe per day since coming on line. 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 six months of 2006, the weighted average realized natural gas price for Questar E&P (including the impact of hedging) was $6.13 per Mcf compared to $4.79 per Mcf for the same period in 2005, a 28% increase. Realized oil and NGL prices for the first six months of 2006 averaged $50.27 per bbl, compared with $39.38 per bbl during the prior year period, a 28% increase. A regional comparison of average realized prices, including hedges, is shown in the following table:

	3 Months Ended			6 Months Ended
	June 30,		%	June 30,		%
	2006	2005	Change	2006	2005	Change
Natural gas (per Mcf)
Rocky Mountains	$5.64	$4.67	21%	$5.84	$4.62	26%
Midcontinent	6.54	5.09	28	6.63	5.11	30
Volume-weighted average	6.00	4.82	24	6.13	4.79	28
Oil and NGL (per bbl)
Rocky Mountains	$48.57	$40.42	20%	$48.65	$39.94	22%
Midcontinent	53.57	39.18	37	53.94	38.14	41
Volume-weighted average	50.11	40.02	25	50.27	39.38	28

Approximately 69% of Questar E&P gas production in the second quarter of 2006 was hedged or pre-sold. For the first six months of 2006, approximately 67% was hedged or pre-sold. Hedging increased gas revenues $18.8 million and $2.8 million during the second quarter and first six months of 2006 respectively. For the current quarter, approximately 80% of Questar E&P oil production was hedged. For the first six months of 2006, approximately 79% was hedged or pre-sold. Oil hedges reduced revenues $6.7 million and $10.4 million during the second quarter and first six months of 2006, respectively.

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 second quarter of 2006, Questar E&P continued to take advantage of high natural gas and oil prices to hedge additional production through 2008. The company has and may continue to enter into basis-only swaps to protect cash flows and earnings from a widening of natural gas price basis differentials that may result from capacity constraints on regional gas pipelines. Derivative positions as of June 30, 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 7% to $2.45 per Mcfe compared to the second quarter of 2005. For the first six months of 2006, controllable production costs rose 7% to $2.41 per Mcfe. Questar E&P controllable production costs are summarized in the following table:

	3 Months Ended				6 Months Ended
	June 30,		%		June 30,		%
	2006	2005	Change		2006	2005	Change
	(Per Mcfe)				(Per Mcfe)
Depreciation, depletion and amortization	$1.38	$1.18	17%		$1.33	$1.16	15%
Lease operating expense	0.54	0.58	(7)		0.54	0.56	(4)
General and administrative expense	0.27	0.31	(13)		0.31	0.33	(6)
Allocated interest expense	0.26	0.21	24		0.23	0.21	10
Controllable production costs	$2.45	$2.28	7%		$2.41	$2.26	7%

Depreciation, depletion and amortization expense rose 17% in the second quarter to $1.38 per Mcfe and 15% to $1.33 per Mcfe for the first six months of 2006 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. For the second quarter of 2006, general and administrative expenses fell to $0.27 per Mcfe compared to $0.31 per Mcfe the same period in 2005 due primarily to the reversal of an accrual related to potential legal expense and higher production volumes. For the first six months of 2006, general and administrative expenses fell to $0.31 per Mcfe compared to $0.33 per Mcfe the same period of 2005. Interest expense per Mcfe of production increased in the current quarter due to refinancing activities and a $50 million increase in long-term debt.

Production taxes were $0.41 per Mcfe in the 2006 quarter compared to $0.50 per Mcfe in the prior year quarter. For the first six months of 2006, production taxes were $0.46 per Mcfe compared to $0.49 per Mcfe in 2005. Most production taxes are based on a fixed percentage of pre-hedge gas, oil, and NGL sales prices. The average pre-hedge gas price per Mcf decreased 7% in the second quarter 2006 and increased 11% in the first six months of 2006 compared to 2005.

Questar E&P’s exploration expense increased $5.0 million in the second quarter 2006 and $6.9 million in the first six months compared to the 2005 periods. The increases were due to expenses for dry exploratory wells. Abandonment and impairment expense increased $0.4 million for the second quarter 2006 and $0.6 million for the first six months of 2006.

#

Pinedale Anticline

As of June 30, 2006, Market Resources (both Questar E&P and Wexpro) operated and had working interest in 149 producing wells on the Pinedale Anticline compared to 109 at the end of the second quarter of 2005. Of the 149 producing wells, Questar E&P has working interests in 129 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 149 producing wells. Market Resources expects to complete between 45 and 48 Lance Pool wells (combined Lance and Mesaverde formations) on its Pinedale acreage during 2006.

 

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

Uinta Basin

During the first six months of 2006, the company drilled or participated in 29 Wasatch and Upper Mesaverde gas wells, 1 horizontal and 1 vertical Green River Formation oil wells, and 2 deeper Blackhawk, Mancos and Dakota formations gas wells 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, averaged approximately 1,100 Mcf per day during its first 90 days online from the deeper section only. Plans call for the well to be completed in uphole zones later this year. A second deep well has been completed in the deeper section and a third is drilling near total depth.

Questar E&P is currently testing several target formations in the Wolf Flat 14C-29-15-19 exploratory well, which is the second well drilled under an Exploration and Development Agreement 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 June 30, 2006, the company had recompleted two older wells, drilled and completed seven new wells, one was waiting on completion and two wells were drilling. 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 second quarter the company continued a 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 spacing 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 has added a second drilling rig and plans to participate in about 24 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 half of 2006 and anticipates participating in an additional three wells during the remainder of 2006.

Wexpro

Wexpro, a Market Resources subsidiary that develops and produces cost-of-service reserves for Questar Gas, reported net income was $12.0 million, compared with $10.5 million for the same period in 2005, a 14% increase. For the first six months of 2006 Wexpro net income was $23.9 million, compared with $20.7 million for the same period in 2005, a 15% increase. 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 investment base at June 30, 2006, increased 17% to $220.1 million up $32.1 million over the year earlier period. Wexpro net income also benefited from 31% higher realized oil and NGL prices versus the second quarter of 2005.

Gas Management

Gas Management, Market Resources gas-gathering and processing-services business, grew net income 13% to $10.2 million in the second quarter of 2006 from $9.0 million in the 2005 period. Net income for the first six months of 2006 was $19.9 million versus $17.8 million for the same period in 2005, a 12% increase. Gas processing plant margin grew 63% from $12.6 million in the first half of 2005 to $20.5 million in the first half of 2006. NGL sales volumes in the first six months of 2006 increased 11% 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 4.9 million MMBtu to 123.7 million MMBtu in the first six 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. In the first six 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 $0.03 decrease in the rate charged per MMBtu processed in the first half comparable periods. To further reduce margin volatility associated with keep-whole contracts, Gas Management began managing NGL price risk in 2004 by using forward-sales contracts. Forward sales contracts increased NGL revenues by $1.3 million in 2006.

Income before tax from Gas Management’s 50% interest in Rendezvous Gas Services, LLC, (Rendezvous), a joint venture that operates gas-gathering facilities in western Wyoming, increased to $3.3 million for the first six months of 2006 versus $3.1 million for 2005, a 6% 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 and Other

Energy Trading, a Market Resources subsidiary that sells Market Resources equity gas and oil, provides risk-management services and operates a natural-gas storage facility, reported net income for the second quarter of 2006 was $1.0 million compared to $0.9 million in 2005, an 11% increase. For the first six months of 2006, net income was $3.5 million compared to $2.2 million for the same period in 2005, a 59% increase. Service fee revenues from affiliates were $0.5 million higher in the second quarter of 2006 and $0.9 million higher in the first six months of 2006 relative to the 2005 periods. Gross margins for gas and oil marketing (gross revenues less costs for gas and oil purchases, transportation and gas storage), increased to $5.8 million for the first six months of 2006 versus $5.7 million a year ago, a 3% increase. The increase in gross margin was due primarily to a 5% increase in volumes and increased storage activity over the same period last year.

Questar Pipeline

Questar Pipeline, a subsidiary that provides interstate natural gas-transportation and storage services, reported net income of $9.9 million for the second quarter of 2006 compared with $7.6 million in the second quarter of 2005. First half 2006 net income was $21.3 million compared with $15.9 in the 2005 period. The higher net income was due to increased transportation and NGL revenues.

Following is a summary of Questar Pipeline’s financial and operating results for the second quarter and first half of 2006 compared with the same periods of 2005:

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
		(in thousands)
OPERATING INCOME
Revenues
Transportation	$ 29,579	$ 26,668	$ 59,650	$  53,254
Storage	9,322	9,254	18,879	18,830
Gas processing	1,359	1,685	2,791	3,467
NGL and other revenues	4,479	2,997	9,427	5,390
Total revenues	44,739	40,604	90,747	80,941
Operating expenses
Operating and maintenance	8,611	8,518	16,161	15,590
General and administrative	4,787	5,816	9,714	11,878
Depreciation and amortization	7,836	7,259	15,748	14,513
Other taxes	1,776	1,665	3,465	3,257
Total operating expenses	23,010	23,258	45,088	45,238
Operating income	$ 21,729	$ 17,346	$ 45,659	$  35,703
OPERATING STATISTICS
Natural gas transportation volumes (in Mdth)
For unaffiliated customers	78,159	61,393	140,876	116,995
For Questar Gas	27,281	26,212	68,138	69,951
For other affiliated customers	5,828	6,505	9,574	8,481
Total transportation	111,268	94,110	218,588	195,427
Transportation revenue (per dth)	$     0.27	$    0.28	$     0.27	$      0.27
Firm-daily transportation demand at      June 30 (Mdth)	2,135	1,815

Revenues

Following is a summary of major changes in Questar Pipeline’s revenues for the three and six months ended June 30, 2006, compared with the same periods of 2005:

	3 Months Ended June 30, 2006 Compared with 2005	6 Months Ended June 30, 2006 Compared with 2005
	(in thousands)
Transportation
New transportation contracts	$4,008	$8,458
Expiration of transportation contracts	(545)	(1,109)
Other transportation	(552)	(953)
Storage	68	49
Gas processing	(326)	(676)
NGL and other revenues
Change in NGL revenues	1,735	3,215
Change in gathering revenue	52	217
Park and loan revenue	(334)	650
Other	29	(45)
Increase	$4,135	$9,806

As of June 30, 2006, Questar Pipeline had firm-transportation contracts of 2,135 Mdth per day compared with 1,815 Mdth per day as of June 30, 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. Since only about 5% of operating costs are recovered through volumetric charges, changes in transportation volumes do not have a significant impact on earnings.

NGL revenues increased in the second quarter and first half of 2006 over the same periods of 2005. NGL volumes increased 92% in the second quarter and 77% in the first half, and NGL prices increased 29% in the second quarter and 36% in the first half relative to the prior periods. NGL revenues were also impacted by the fuel-gas reimbursement percentage proceedings as discussed below.

Revenues from park and loan services increased in the first half of 2006 over the first half 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. Beginning in the second quarter additional revenues received in 2006 are being 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 $0.7 million recorded in the first half of 2005.

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

On June 17, 2005, Questar Pipeline filed an uncontested offer of settlement with the FERC to resolve the outstanding issues in the 2004 and 2005 FGRP filings. This settlement with customers was approved July 26, 2005, and contains the following terms: (a) the settlement will cover the period from June 1, 2005 through December 31, 2007; (b) no adjustments will be made to FGRP amounts collected by Questar Pipeline prior to June 2005; (c) one-half of the Kastler plant liquid revenues from August 2001 through December 2007 will be refunded to customers and the remaining revenues will be retained by Questar Pipeline; and (d) Questar Pipeline will reduce the FGRP amount collected from customers from 2.6% to 2.1% effective June 1, 2005. This percentage consists of 1.95% of ongoing FGRP related 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 $0.9 million in the second quarter of 2006 and $1.6 million in the first half of 2006 compared with the 2005 periods. Beginning in July 2005 customers at the company’s Price, Utah plant began supplying their own fuel gas, which accounted for about half of the decrease. Operating, maintenance, general and administrative expenses per decatherm transported declined from $0.14 in the first half of 2005 to $0.12 in the first half of 2006.

Depreciation expense increased 8% in the second quarter of 2006 and 9% in the first half of 2006 over the same periods 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 five additional pressure tests from April 2004 to April 2006 to validate the model.

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 discussed with the FERC the recording of the loss of gas as a reduction of native gas remaining in the reservoir that 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 tax.

Questar Gas

Questar Gas, that provides natural gas distribution services in Utah, Wyoming and Idaho, reported a seasonal net loss of $0.7 million in the second quarter of 2006 compared with a net loss of $3.4 million in the second quarter of 2005. Questar Gas net income was $28.7 million in the first half of 2006 compared with $25.3 million in the first half of 2005. The improved 2006 results were from higher margins from customer growth and the recovery of gas-processing costs in 2006 that were not recognized in 2005 results until the fourth quarter.

Following is a summary of Questar Gas’s financial and operating results for the second quarter and first half of 2006 compared with the same periods of 2005:

#

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
		(in thousands)
OPERATING INCOME
Revenues
Residential and commercial sales	$162,398	$131,737	$603,891	$453,783
Industrial sales	8,366	8,694	18,006	19,101
Transportation for industrial customers	1,395	1,298	3,006	2,905
Other	10,931	10,684	26,703	21,575
Total revenues	183,090	152,413	651,606	497,364
Cost of natural gas sold	137,966	112,359	509,108	363,956
Margin	45,124	40,054	142,498	133,408
Operating expenses
Operating and maintenance	17,324	17,846	38,398	35,871
General and administrative	10,746	10,160	20,359	21,046
Depreciation and amortization	10,593	10,892	22,165	22,198
Other taxes	3,726	3,278	7,334	6,464
Total operating expenses	42,389	42,176	88,256	85,579
Operating income (loss)	$  2,735	$ (2,122)	$ 54,242	$ 47,829
OPERATING STATISTICS
Natural gas volumes (in Mdth)
Residential and commercial sales	16,692	16,843	58,957	56,762
Industrial sales	1,126	1,394	2,277	3,097
Transportation for industrial customers	7,384	7,068	15,869	15,723
Total deliveries	25,202	25,305	77,103	75,582
Natural gas revenue (per dth)
Residential and commercial sales	$   9.73	$   7.82	$  10.24	$   7.99
Industrial sales	7.44	6.24	7.91	6.17
Transportation for industrial customers	$   0.19	$   0.18	$   0.19	$   0.18
Heating degree days – colder (warmer)      than normal	(25%)	6%	(7%)	(3%)
Average temperature adjusted usage
per customer (dth)	18.1	18.2	68.5	68.1
Customers at June 30,	835,511	798,277

Margin Analysis

Questar Gas margin (revenues less gas costs) increased $5.1 million in the second quarter and $9.1 million in the first half of 2006 compared to the same periods of 2005. Following is a summary of major changes in Questar Gas margin:

	3 Months Ended June 30, 2006 Compared with 2005	6 Months Ended June 30, 2006 Compared with 2005
	(in thousands)
New customers	$1,224	$4,683
Change in usage per customer	(260)	879
Gas processing revenues    collected from customers	1,189	2,605
Interest on past-due receivables	258	548
Recovery of bad debt gas costs	(636)	803
Change in unbilled estimate	2,727
Other	568	(428)
Increase	$5,070	$9,090

Temperature-adjusted usage per customer was flat in the second quarter and first half of 2006 compared to the same periods of 2005. Weather, as measured in degree days, was 25% warmer than normal in the second quarter of 2006 compared to 6% colder than normal in the second quarter of 2005. For the first half of 2006, weather was 7% warmer than normal compared with 3% warmer than normal in 2005. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations. Questar Gas adjusted its estimate of unbilled revenues during the second quarter of 2006, increasing the margin by $2.7 million. At June 30, 2006, Questar Gas was serving 835,511 customers, up from 824,447 at December 31, 2005.

Industrial deliveries (including sales and transportation) increased 1% in the second quarter of 2006 and decreased 4% in the first half of 2006 compared to 2005. The first half decrease was primarily driven by lower power-generation requirements.

As discussed below, Questar Gas received rate coverage for gas-processing costs in the second quarter of 2006 of $1.2 million and the first half of 2006 of $2.6 million. Rate coverage for costs incurred in the prior year was not recognized until the fourth quarter of 2005, pursuant to a February 2006 regulatory order.

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 decreased the second quarter 2006 margin by $0.6 million and increased the first half 2006 margin by $0.8 million.

Expenses

Cost of natural gas sold increased 23% in the second quarter and 40% in the first half of 2006 compared with 2005 periods due primarily to increased gas purchase cost per dth. Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the PSCU and the PSCW. Purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. As of June 30, 2006, Questar Gas had a $28.5 million over collection balance in the purchased-gas adjustment account representing gas recovered from customers in excess of costs incurred. Rates in Utah effective June 2006 were 9% higher than a year earlier although rates during a portion of the 2006 winter heating season were 42% higher than the prior year.

Operating, maintenance, general and administrative expenses were flat in the second quarter of 2006 and up 3% in the first half of 2006 compared to 2005 periods. Bad debt costs were $1.0 million higher in the first half of 2006. As noted earlier, the gas-cost portion of bad debts is recovered through the gas balance account.

Depreciation expense decreased 3% in the second quarter of 2006 and was flat in the first half of 2006 compared to 2005 periods. As explained in Part I, Item 1. Financial Statements Note 9, Questar Gas reduced its depreciation rates effective June 1, 2006, in accordance with a PSCU order. This offset the depreciation impact of plant additions from customer growth.

Gas processing cost recovery

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

See Part I, Item 1. Financial Statements Note 9 for a discussion of the Conservation Enabling Tariff and a rate reduction in Utah.

Consolidated Results after Operating Income

Income from unconsolidated affiliates

Gas Management has a 50% interest in Rendezvous that provides gas-gathering services for the Pinedale and Jonah producing areas of western Wyoming. Gas Management’s share of Rendezvous’ earnings before tax were flat at $1.6 million in the second quarter of 2006 and the second quarter of 2005 and $3.3 million in the first half of 2006 versus $3.1 million in the first half of 2005. Rendezvous gathering volumes decreased 2% in the second quarter of 2006 and increased 4% in the first half of 2006 compared to the year earlier periods.

Interest expense and loss on early extinguishment of debt

Interest expense rose in the first half of 2006 due to Market Resources refinancing activities and the interest charges on a $50 million net increase in long-term debt borrowed in May 2006. Market Resources recognized a $1.7 million pre-tax loss on the early extinguishment of its 7% Notes due 2007.

Unrealized mark-to-market loss on basis swaps

Market Resources entered into NYMEX/Rockies basis swaps to protect cash flows and earnings from a widening of natural gas price basis differentials due to capacity constraints on gas pipelines transporting gas from the Rockies region. The company recorded an unrealized mark-to-market loss of $5.6 million on the NYMEX/Rockies basis swaps in the second quarter of 2006.

Income taxes

The effective combined federal and state income tax rate was 37.1% in the first half of both 2006 and 2005.

Liquidity and Capital Resources

Operating Activities

	6 Months Ended
	June 30,
	2006	2005
	(in thousands)
Net income	$227,518	$155,898
Noncash adjustments to net income	182,442	143,654
Changes in operating assets and liabilities	93,129	26,794
Net cash provided from operating activities	$503,089	$326,346

Net cash provided from operating activities increased 54% in the first six months of 2006 compared to the same period last year because of higher net income and lower hedging collateral deposits. Hedging collateral deposits were zero at June 30, 2006, compared with $62.6 million at June 30, 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 half of 2006 and 2005 plus a forecast for calendar year 2006 are presented below:

			Forecast
	6 Months Ended		12 Months Ended
	June 30,		December 31,
	2006	2005	2006
Market Resources	$305,324	$208,914	$693,900
Questar Pipeline	12,172	38,268	122,400
Questar Gas	44,639	35,151	99,100
Corporate and other operations	316	787	800
Total	$362,451	$283,120	$916,200

Market Resources expanded Rockies, Uinta Basin and Midcontinent drilling programs represented the majority of the increase in capital expenditures for the first six 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 half of 2006. On May 11, 2006, Market Resources sold $250 million principal amount of 6.05% Notes due 2016. Net proceeds of $247 million were used for general corporate purposes including the June 14, 2006 early extinguishment of its $200 million of 7% Notes due 2007. Market Resources recorded a $1.7 million pre-tax charge related to the early extinguishment of the 7% Notes. Total debt was 35% of total capital at June 30, 2006.

The Company had $490 million of short-term lines of credit available at June 30, 2006, but no amount borrowed.

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-derivative 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. Derivative 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.

Generally derivative instruments 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. Changes in the fair value of cash-flow hedges are recorded on the balance sheet and in other comprehensive income or loss until the underlying gas or oil is produced. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. The ineffective portion of cash flow hedges is immediately recognized in the determination of net income. The ineffective portion of cash flow hedges was not significant in the first half of 2006 or 2005.

Market Resources also entered into natural gas basis-only swaps in the second quarter of 2006 to manage the risk of a widening of basis differentials in the Rocky Mountains. These contracts are marked-to-market with any change in the valuation recognized in the determination of net income.

Market Resources enters into commodity price derivative 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 contracts. 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 June 30, 2006.

A summary of Market Resources derivative positions for equity production as of June 30, 2006, is shown below. Currently fixed-price and basis-only swaps are with creditworthy counterparties. Prices for fixed-price swaps, allow Market Resources to realize a known price for a specific volume of production delivered into a regional sales point. The fixed-price 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) Fixed-Price Swaps				Average price per Mcf, net to the well
2006
Second half		26.1	12.2	38.3		$5.93	$6.81	$6.21
2007
First half		19.8	10.1	29.9		$7.02	$7.82	$7.29
Second half		20.1	10.3	30.4		7.02	7.82	7.29
12 months		39.9	20.4	60.3		7.02	7.82	7.29
2008
First half		13.5	6.9	20.4		$7.20	$8.06	$7.49
Second half		13.7	6.9	20.6		7.20	8.06	7.49
12 months		27.2	13.8	41.0		7.20	8.06	7.49
		Gas (in Bcf) Basis-Only Swaps				Estimated Average basis per Mcf vs. NYMEX
2006
Second half		8.3		8.3		$2.07		$2.07
2007
First half		6.7		6.7		$1.96		$1.96
Second half		6.9		6.9		1.96		1.96
12 months		13.6	0.0	13.6		1.96		1.96

#

2008
First half		10.2		10.2		$1.64		$1.64
Second half		10.3		10.3		1.64		1.64
12 months		20.5	0.0	20.5		1.64		1.64
		Oil (in Mbbl) Fixed-Price Swaps				Average price per bbl, net to the well
2006
Second half		626	202	828		$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

As of June 30, 2006, Market Resources held commodity-price hedging contracts covering about 171.6 million MMBtu of natural gas, 2.7 MMbbl of oil and 33.8 million gallons of NGL. A year earlier Market Resources hedging contracts covered 175.5 million MMBtu of natural gas and 2.2 MMbbl of oil. Market Resources has also entered into basis-only swaps on an additional 42.4 million MMBtu of natural gas. There were no basis-only swaps a year earlier.

The following table summarizes changes in the fair value of derivative contracts from December 31, 2005 to June 30, 2006:

	Fixed-Price Swaps	Basis-Only Swaps	Total
	(in thousands)
Net fair value of gas- and oil-derivative contracts    outstanding at December 31, 2005	($319,121)		($319,121)
Contracts realized or otherwise settled	100,235		100,235
Change in gas and oil prices on futures markets	171,807		171,807
Contracts added since December 31, 2005	11,499	($5,614)	5,885
Net fair value of gas- and oil-derivative contracts    outstanding at June 30, 2006	($35,580)	($5,614)	($41,194)

A table of the net fair value of gas- and oil-derivative contracts as of June 30, 2006, is shown below. About 55% of the fair value of all contracts will settle in the next twelve months and the fair value of cash-flow hedges will be reclassified from other comprehensive income:

	Fixed-Price Swaps	Basis-Only Swaps	Total
	(in thousands)
Contracts maturing by June 30, 2007	($19,561)	($4,505)	($24,066)
Contracts maturing between May 1, 2007 and    June 30, 2008	(23,048)	(752)	(23,800)
Contracts maturing between May 1, 2008 and    June 30, 2009	7,029	(357)	6,672
Net fair value of gas- and oil-derivative contracts at    June 30, 2006	($35,580)	($5,614)	($41,194)

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

	At June 30,
	2006	2005
	(in millions)
Mark-to-market valuation – liability	($41.2)	($215.6)
Value if market prices of gas and oil and basis differentials decline by 10%	87.8	(105.8)
Value if market prices of gas and oil and basis differentials increase by 10%	(171.3)	(325.5)

Interest-Rate Risk Management

As of June 30, 2006, Questar had $1,032.4 million of fixed-rate long-term debt 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.

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. Opposing motions to dismiss or consolidate the lawsuits have been filed. The Hartman parties have also filed motions for partial summary judgment. All motions are pending with the court.

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. Kaiser-Francis filed a petition for certiorari which the Oklahoma Supreme Court has denied and the case has been dismissed with prejudice.

Consonus Case.  Consonus, its parent company (Questar InfoComm) and certain named officers and directors of Consonus were named as defendants in a lawsuit, Melnyk v. Consonus, Inc., Case No. 2:03-CV-00528DB, filed in a federal district court. The plaintiffs are former minority shareholders who include a former officer and a former director and officer. They claimed that the majority shareholders breached their fiduciary duties to minority shareholders by wasting assets and engaging in related-party transactions to the detriment of minority shareholders. Plaintiffs also alleged that they received an inadequate price for their shares in a statutory merger that occurred in mid-2003. A federal district judge, by an order dated January 26, 2006, dismissed this action with prejudice finding that plaintiffs’ claims were without merit. On February 17, 2006, defendants filed a motion for attorney fees and costs. On February 24, 2006, plaintiffs filed a notice of appeal. The parties have settled the case with each side dismissing with prejudice their respective claims and counterclaims.

Environmental Claims.  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 believes it is operating the facilities and filing necessary reports in compliance with regulatory requirements; however, the EPA contends such facilities are located within Indian Country and are subject to additional Clean Air Act requirements not applicable to non-Indian Country lands administered by the state of Utah. As a consequence, EPA has broadened its allegations to include additional potential ongoing 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. These potential violations will likely result in civil penalties of an unknown and undetermined amount but in excess of $100,000.

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 June 30, 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
April 1, 2006 – April 30, 2006	1,925	$79.52	-	-
May 1, 2006 – May 31, 2006	14,042	80.25	-	-
June 1, 2006 – June 30, 2006	3,516	77.82	-	-
Total	19,483	$79.74	-	-

*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 shares of restricted stock forfeited when failing to satisfy vesting conditions.

Item 4.  Submission of Matters to a Vote of Security Holders

The Company held its Annual Meeting on May 16, 2006. The following individuals were elected at the meeting to serve three-year terms as directors: Keith O. Rattie, M. W. Scoggins, and Harris H. Simmons. Additionally, one director, Bruce A. Williamson, was elected to serve a two-year term. There was no solicitation in opposition to the nominees. The following is a tabulation of the votes received by nominees elected at the meeting:

Name	Votes For	Votes Withheld
K. O. Rattie	73,983,827	1,896,896
M. W. Scoggins	73,762,716	2,118,007
Harris H. Simmons	71,139,634	4,741,089
Bruce A. Williamson	74,756,253	1,124,470

The Company’s directors are divided into three classes. Other directors whose terms extend beyond the meeting include: Teresa Beck, R. D. Cash, Robert E. McKee III, Gary G. Michael, Charles B. Stanley, Phillips S. Baker, Jr., L. Richard Flury, and James A. Harmon.

Item 5.  Other Information

Robert E. Kadlec retired as a director effective May 16, 2006, because he had reached the mandatory retirement age of 72. At the time of his retirement, Mr. Kadlec was serving as Chair of the Management Performance Committee. Mr. Kadlec’s retirement leaves a vacancy on the Board of Directors. On May 16, 2006, Mr. Kadlec was replaced as Chair of the Management Performance Committee by L. Richard Flury. Mr. Flury has served as a director of the Company since 2002.

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Item 6.  Exhibits

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

Exhibit No.

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.

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

SIGNATURES

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

QUESTAR CORPORATION

(Registrant)

August 4, 2006

/s/Keith O. Rattie

Keith O. Rattie, Chairman of the Board,

President and Chief Executive Officer

August 4, 2006

/s/S. E. Parks

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.

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.

Exhibit 31.1.

CERTIFICATION

I, Keith O. Rattie, certify that:

1.

I have reviewed this quarterly report of Questar Corporation on Form 10-Q for the period ending June 30, 2006;

2.

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

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

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

a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

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

c)

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

d)

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

5.

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

a)

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

b)

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

August 4, 2006

/s/Keith O. Rattie

Keith O. Rattie,

Chairman, President and Chief

Executive Officer

Exhibit 31.2.

CERTIFICATION

I, S. E. Parks, certify that:

1.

I have reviewed this quarterly report of Questar Corporation on Form 10-Q for the period ending June 30, 2006;

2.

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

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

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

a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

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

c)

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

d)

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

5.

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

a)

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

b)

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

August 4, 2006

/s/S. E. Parks

S. E. Parks

Senior Vice President

and Chief Financial Officer

Exhibit No. 32.

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Questar Corporation (the Company) on Form 10-Q for the period ending June 30, 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

#

August 4, 2006

/s/Keith O. Rattie

Keith O. Rattie

Chairman, President and Chief Executive Officer

August 4, 2006

/s/S. E. Parks

S. E. Parks

Senior Vice President and Chief Financial Officer

#