Edgar Filing: QUESTAR CORP

UNITED STATES

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]

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

For the quarter ended September 30, 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 October 31, 2006, 85,865,721 shares of the registrant’s common stock, without par value, were outstanding.

Questar Corporation

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

TABLE OF CONTENTS

Page

PART I.

FINANCIAL INFORMATION

Item 1.

Financial Statements (Unaudited)

Consolidated Statements of Income for the three and nine months ended

September 30, 2006 and 2005

Condensed Consolidated Balance Sheets as of September 30, 2006

and December 31, 2005

Condensed Consolidated Statements of Cash Flows for the nine months ended

September 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 6.

Exhibits

Signatures

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

QUESTAR CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2006	2005	2006	2005
	(in thousands, except per share amounts)
REVENUES
Market Resources	$427,907	$446,746	$1,227,094	$1,105,980
Questar Pipeline	25,793	22,584	76,147	59,583
Questar Gas	98,975	109,575	747,767	604,308
Corporate and other operations	2,468	4,0 05	11,738	13,572

TOTAL REVENUES	555,143	582,910	2,062,746	1,783,443

OPERATING EXPENSES
Cost of natural gas and other products sold	183,684	271,724	867,318	836,106
Operating and maintenance	69,514	67,057	211,867	187,116
General and administrative	34,083	31,112	96,693	93,842
Production and other taxes	27,832	30,864	87,168	83,499
Depreciation, depletion and amortization	78,808	63,542	224,831	182,174
Exploration	16,847	2,574	30,247	9,423
Abandonment and impairment of gas,
oil and other properties	1,955	1,712	5,497	4,610

TOTAL OPERATING EXPENSES	412,723	468,585	1,523,621	1,396,770

OPERATING INCOME	142,420	114,325	539,125	386,673

Net gain on asset sales	25,328	1,128	25,509	4,722
Interest and other income	3,709	3,935	9,685	5,914
Income from unconsolidated affiliates	1,801	1,910	5,333	5,131
Net unrealized mark-to-market loss on basis swaps net	(5,140)		(10,754)
Loss on early extinguishment of debt			(1,746)
Interest expense	(17,814)	(17,869)	(55,006)	(51,234)

INCOME BEFORE INCOME TAXES	150,304	103,429	512,146	351,206
Income taxes	55,248	37,672	189,572	129,551

NET INCOME	$ 95,056	$ 65,757	$ 322,574	$ 221,655

EARNINGS PER COMMON SHARE
Basic	$ 1.11	$ 0.78	$ 3.78	$ 2.62
Diluted	1.08	0.75	3.68	2.55

Weighted average common shares outstanding
Used in basic calculation	85,544	84,930	85,388	84,674
Used in diluted calculation	87,706	87,353	87,558	87,043
Dividends per common share	$ 0.235	$ 0.225	$ 0.695	$ 0.665

See notes accompanying the consolidated financial statements

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QUESTAR CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,	December 31,
	2006	2005
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$ 77,707	$ 13,360
Accounts receivable, net	223,507	355,810
Unbilled gas accounts receivable	13,947	86,161
Federal income tax recoverable	18,940	11,274
Derivative collateral deposits		5,150
Fair value of derivative contracts	104,709	1,972
Inventories, at lower of average cost or market
Gas and oil storage	81,193	90,718
Materials and supplies	64,734	34,699
Prepaid expenses and other	24,045	30,110
Purchased-gas adjustments		39,852
Deferred income taxes – current		86,734
Total current assets	608,782	755,840
Property, plant and equipment	6,086,099	5,527,997
Less accumulated depreciation, depletion and amortization	2,251,751	2,100,455
Net property, plant and equipment	3,834,348	3,427,542
Investment in unconsolidated affiliates	37,437	30,681
Goodwill	70,719	71,260
Fair value of derivative contracts	51,990
Regulatory assets	34,017	32,767
Other noncurrent assets, net	39,852	38,983
	$4,677,145	$4,357,073

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt		$ 94,500
Accounts payable and accrued expenses	$ 373,500	526,196
Questar Gas customer-credit balances	32,367	30,829
Fair value of derivative contracts	13,201	222,049
Purchased-gas adjustments	29,292
Deferred income taxes - current	20,446
Total current liabilities	468,806	873,574
Long-term debt, less current portion	1,032,394	983,200
Deferred income taxes	763,888	624,187
Asset retirement obligations	110,224	78,123
Pension and post-retirement benefits	56,692	61,049
Fair value of derivative contracts	176	99,044
Other long-term liabilities	113,289	88,093

Common shareholders’ equity
Common stock	403,942	383,298
Retained earnings	1,648,832	1,385,783
Accumulated other comprehensive income (loss)	78,902	(219,278)
Total common shareholders’ equity	2,131,676	1,549,803
	$4,677,145	$4,357,073

See notes accompanying the consolidated financial statements

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QUESTAR CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	9 Months Ended
	September 30,
	2006	2005
	(in thousands)
OPERATING ACTIVITIES
Net income	$ 322,574	$ 221,655
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	230,895	187,293
Deferred income taxes	65,166	72,997
Share-based compensation	6,907	2,990
Abandonment and impairment of gas, oil and other properties	5,497	4,610
Income from unconsolidated affiliates	(5,333)	(5,131)
Distributed income from unconsolidated affiliates	4,902	4,342
Net gain on asset sales	(25,509)	(4,722)
Net unrealized mark-to-market loss on basis swaps	10,754
Loss on early extinguishment of debt	1,746
Ineffective portion of fixed-price swaps	(106)	390
Changes in operating assets and liabilities	116,499	(179,313)
NET CASH PROVIDED FROM OPERATING ACTIVITIES	733,992	305,111

INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(597,716)	(481,124)
Other investments	(6,325)	(6,787)
Total capital expenditures	(604,041)	(487,911)
Proceeds from disposition of assets	29,489	15,960
NET CASH USED IN INVESTING ACTIVITIES	(574,552)	(471,951)

FINANCING ACTIVITIES
Common stock issued	9,272	15,809
Common stock repurchased	(5,469)	(9,246)
Long-term debt issued, net of issue costs	246,953	200,000
Long-term debt repaid	(200,012)	(8)
Early extinguishment of debt costs	(1,746)
Change in short-term debt	(94,500)	24,000
Dividends paid	(59,525)	(56,432)
Excess tax benefits from share-based compensation	9,934
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES Change in cash and cash equivalents Beginning cash and cash equivalents	(95,093)	174,123
	64,347	7,283
	13,360	3,681
Ending cash and cash equivalents	$ 77,707	$ 10,964


See notes accompanying the consolidated financial statements

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NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – 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, oil and NGL. Wexpro Company (Wexpro) manages, develops and produces cost-of-service reserves for gas utility affiliate Questar Gas. Questar Gas Management Company (Gas Management) provides midstream field services including natural 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.

Note 2 – Summary of Significant Accounting Policies

Basis of Presentation of Interim Consolidated Financial Statements

The interim consolidated financial statements contain the accounts of Questar and its majority-owned or controlled subsidiaries. The consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) and with the instructions for quarterly reports on Form 10-Q and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.

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. 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 nine months ended September 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 located in Item 3 of this report.

Derivative Collateral Deposits

Derivative collateral deposits represent cash collateral deposited with counterparties under the terms of derivative agreements. Some counterparties may require the Company to deposit cash collateral when the derivatives under these agreements are out-of-the-money by an amount that exceeds counterparty credit limits. The deposits are restricted until either the derivative transaction returns to in-the-money status or the open position is settled.

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Investment in Unconsolidated Affiliates

Questar uses the equity method to account for investment in unconsolidated affiliates where it does not have control, but has significant influence. Generally, the investment in unconsolidated affiliates on the Company’s Consolidated Balance Sheets equals the Company’s proportionate share of equity reported by the unconsolidated affiliates. Investment is assessed for possible impairment when events indicate that the fair value of the investment may be below the Company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in net income.

Property, Plant and Equipment

Capitalized exploratory well costs

The Company capitalizes exploratory well costs until it determines whether the well is commercial or noncommercial. If the Company deems the well commercial, capitalized costs are depreciated on a field basis using the unit-of-production method and the estimated proved developed gas and oil reserves. If the Company concludes that the well is noncommercial, well costs are immediately charged to exploration expense. Exploratory well costs capitalized for a period greater than one year since the completion of drilling are expensed unless the Company remains engaged in substantial activities to assess whether the well is commercial.

Depreciation, depletion and amortization

Capitalized proved leasehold costs are depleted on a field-by-field basis using the unit-of-production method and the estimated proved gas and oil reserves. 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. Capitalized costs of exploratory wells that have found proved gas and oil reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves on a field basis. The Company capitalizes an estimate of the fair value of future abandonment costs. Future abandonment costs, less estimated future salvage values, are depreciated over the life of the related asset using a unit-of-production method.

Note 3 – Earnings Per Share (EPS)

Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the reporting 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

September 30,

9 Months Ended

September 30,

2006

2005

2006

2005

(in thousands)

Weighted-average basic common shares

outstanding

85,544

84,930

85,388

84,674

Potential number of shares issuable from exercising stock options and from nonvested restricted shares

2,162

2,423

2,170

2,369

Weighted-average diluted common shares

outstanding

87,706

87,353

87,558

87,043

Questar issued 614,000 and 964,000 shares for the Long-Term Stock Incentive Plan (LTSIP) and other plans in the first nine months of 2006 and 2005, respectively.

Employee Investment Plan (EIP)

The EIP allows eligible employees to purchase shares of Questar common stock or other investments through payroll deduction at the current fair market value on the transaction date. The

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Company currently contributes an overall match of 80% of employees’ pre-tax purchases up to a maximum of 6% of their qualifying earnings. In addition, the Company contributes $200 annually to the EIP for each eligible employee. The EIP trustee purchases Questar shares on the open market as cash contributions are received. The Company recognizes expense equal to its contributions which amounted to $4.9 million and $4.5 million for the nine months ended September 30, 2006 and 2005, respectively.

Note 4 – Share-Based Compensation

Questar issues stock options and restricted shares to certain officers, employees and non-employee directors under its LTSIP. Prior to January 1, 2006, the Company accounted for share-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion (APBO) 25 “Accounting for Stock Issued to Employees” and related interpretations. No compensation cost was recorded for stock options 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 Statement of Financial Accounting Standards 123R “Share Based Payment,” (SFAS 123R) 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 nine months ended September 30, 2006, were approximately $1.3 million and $0.8 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 nine months ended September 30, 2006, by $0.05 per share. Share-based compensation associated with unvested restricted shares for the nine months ended September 30, 2006 and 2005, amounted to $5.6 million and $3.0 million, respectively. At September 30, 2006, deferred share-based compensation amounted to $15.7 million, of which $3.6 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 nine months ended September 30, 2006, this requirement reduced net cash provided from operating activities and reduced net cash used in financing activities by $9.9 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	9 Months Ended
	September 30,	September 30,
	2005	2005
	(in thousands)

Net income, as reported	$65,757	$221,655
Deduct after-tax share-based compensation expense under fair-value based method	(402)	(1,206)
Pro forma net income	$65,355	$220,449

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Earnings per share
Basic, as reported	$ 0.78	$ 2.62
Basic, pro forma	0.77	2.60
Diluted, as reported	0.75	2.55
Diluted, pro forma	$ 0.75	$ 2.53

Long-Term Stock Incentive Plan

There were 5,352,091 shares available for future grant at September 30, 2006. The Company granted restricted shares but did not grant stock options in the first nine months of 2006. Transactions involving stock options in the LTSIP in the first nine months 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	(482,445)	15.00 – 35.10	23.87
Balance at September 30, 2006	2,769,543	$15.00 – $77.14	$28.51

Unvested stock options declined by 230,686 to 232,689 in the first nine months of 2006.

Options Outstanding				Options Exercisable		Unvested Options
Range of exercise prices	Number outstanding at Sept. 30, 2006	Weighted-average remaining term in years	Weighted-average exercise price	Number exercisable at Sept. 30, 2006	Weighted-average exercise price	Number unvested at Sept. 30, 2006	Weighted average exercise price

$15.00 – $17.00	435,052	3.2	$15.43	435,052	$15.43
19.13 – 23.95	632,420	4.7	22.75	632,420	22.75
27.11 – 29.71	1,438,132	5.5	27.48	1,438,132	27.48
$35.10 – 77.14	263,939	6.6	69.52	31,250	45.95	232,689	$72.69
	2,769,543	5.1	$28.51	2,536,854	$24.46	232,689	$72.69

Most restricted share grants vest in equal installments over a three to five year period from the grant date. Several grants vest in a single installment after a specified period. The weighted average vesting period of unvested restricted shares at September 30, 2006, was 18 months. Transactions involving restricted shares in the LTSIP in the first nine months 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	157,715	68.22 – 89.54	73.94
Distributed	(79,845)	27.11 – 77.06	34.33
Forfeited	(2,645)	28.72 – 75.99	62.92
Balance at September 30, 2006	375,266	$27.11 – $89.54	$55.61

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Note 5 – Operations by Line of Business

Line of business information is presented according to senior management’s basis for evaluating performance including differences in the nature of products, services and regulation. Following is a summary of operations by line of business for the three and nine months ended September 30, 2006 and 2005:

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2006	2005	2006	2005
		(in thousands)

REVENUES FROM UNAFFILIATED CUSTOMERS
Questar E&P	$206,033	$158,269	$ 615,205	$ 428,116
Wexpro	6,104	6,228	16,076	14,779
Gas Management	41,518	35,561	123,251	97,743
Energy Trading and other	174,252	246,688	472,562	565,342
Market Resources total	427,907	446,746	1,227,094	1,105,980
Questar Pipeline	25,793	22,584	76,147	59,583
Questar Gas	98,975	109,575	747,767	604,308
Corporate and other operations	2,468	4,005	11,738	13,572
	$555,143	$582,910	$2,062,746	$1,783,443

REVENUES FROM AFFILIATED CUSTOMERS
Wexpro	$ 36,384	$ 31,657	$ 111,627	$ 97,845
Gas Management	3,884	3,110	11,362	9,698
Energy Trading and other	148,180	139,170	557,358	412,925
Market Resources total	188,448	173,937	680,347	520,468
Questar Pipeline	19,100	20,182	59,493	64,124
Questar Gas	1,728	1,769	4,542	4,400
Corporate and other operations	399	384	1,235	1,459
	$209,675	$196,272	$ 745,617	$ 590,451
OPERATING INCOME (LOSS)
Questar E&P	$ 92,592	$ 76,405	$ 315,485	$ 200,365
Wexpro	18,657	16,850	55,168	48,599
Gas Management	15,972	10,281	45,744	36,339
Energy Trading and other	3,730	2,878	7,825	6,892
Market Resources total	130,951	106,414	424,222	292,195
Questar Pipeline	21,938	20,218	67,597	55,921
Questar Gas	(11,273)	(12,519)	42,969	35,310
Corporate and other operations	804	212	4,337	3,247
	$142,420	$114,325	$ 539,125	$ 386,673
NET INCOME (LOSS)
Questar E&P	$ 66,045	$ 44,753	$ 192,635	$ 115,430
Wexpro	12,130	11,251	36,072	31,928
Gas Management	10,999	7,299	30,923	25,069
Energy Trading and other	2,828	1,976	6,322	4,234
Market Resources total	92,002	65,279	265,952	176,661
Questar Pipeline	10,147	9,223	31,470	25,155
Questar Gas	(9,157)	(9,905)	19,514	15,361
Corporate and other operations	2,064	1,160	5,638	4,478
	$ 95,056	$ 65,757	$ 322,574	$ 221,655

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Note 6 – 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		9 Months Ended
	September 30,		September 30,
	2006	2005	2006	2005
		(in thousands)

Service cost	$ 2,153	$ 2,184	$ 7,283	$ 6,553
Interest cost	5,696	5,170	16,592	15,510
Expected return on plan assets	(5,334)	(4,947)	(15,702)	(14,840)
Prior service and other costs	298	320	894	959
Recognized net-actuarial loss	1,691	877	4,193	2,631
Amortization of early-retirement costs		725		2,175
Qualified pension expense	$ 4,504	$ 4,329	$ 13,260	$ 12,988

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		9 Months Ended
	September 30,		September 30,
	2006	2005	2006	2005
		(in thousands)

Service cost	$ 197	$ 200	$ 663	$ 600
Interest cost	1,108	1,150	3,414	3,450
Expected return on plan assets	(757)	(739)	(2,221)	(2,217)
Amortization of transition obligation	469	469	1,409	1,408
Amortization of losses	39	20	139	61
Accretion of regulatory liability	200	200	600	600
Postretirement benefits expense	$ 1,256	$ 1,300	$ 4,004	$ 3,902

Note 7 – Disposition of Property

On August 30, 2006, Questar E&P sold certain proved reserves and undeveloped leasehold interests in western Colorado and recognized a pre-tax gain of $22.7 million. The gain is included in the Consolidated Statement of Income line item “Net gain on asset sales”. For income tax purposes, the Company structured the sale of the Colorado properties and the March 2006 acquisition of certain Louisiana properties to qualify as a reverse like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended.

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Note 8 – 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. Revisions to estimates of the ARO result from changes in expected cash flows. 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)

ARO liability at January 1,	$ 78,123	$67,288
Accretion	4,616	3,148
Liabilities incurred	7,057	3,010
Revisions	22,340
Liabilities settled	(1,912)	(724)
ARO liability at September 30,	$110,224	$72,722

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 funds related to estimated ARO costs. The funds are used to satisfy retirement obligations as the properties are abandoned. At September 30, 2006, approximately $4.6 million was held in this trust invested primarily in a short-term bond index fund.

Note 9 – Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs for the first nine months 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	1,998
Reclassifications to property, plant and equipment after the
determination of proved reserves	(5,030)
Capitalized exploratory well costs charged to expense	(11,484)
Balance at September 30,	$ 1,998

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

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	September 30,	December 31,
	2006	2005
	(in thousands)

Capitalized exploratory well costs that have been capitalized
one year or less	$1,998	$16,514
Capitalized exploratory well costs that have been capitalized
longer than one year
Balance at end of period	$1,998	$16,514

10 – Other Regulatory Assets and Liabilities

The Company has other regulatory assets and liabilities in addition to purchased-gas adjustments that are described in Note 1 of the consolidated financial statements included in its 2005 Annual Report filed on Form 10-K. The regulated entities recover these costs but do not generally receive a return on these assets.

Following is a description of the Company’s regulatory assets:

•

Gains and losses on the reacquisition of debt by rate-regulated companies are deferred and amortized as interest expense over the would-be remaining life of the reacquired debt. The reacquired debt costs had a weighted-average life of approximately 11 years as of September 30, 2006.

•

Questar Gas has a regulatory asset that represents future expenses related to abandonment of Wexpro operated gas and oil wells. The regulatory asset will be reduced over an 18 year period following an amortization schedule that commenced January 1, 2003, or as cash is paid to plug and abandon wells.

•

Production taxes on cost-of-service gas production are recorded when the gas is produced and recovered from customers when taxes are paid, generally within 12 months.

•

The rate-regulated businesses are allowed to recover certain deferred taxes from customers over the life of the related property, plant and equipment.

•

The costs of complying with pipeline-integrity regulations are recovered in rates subject to a Public Service Commission of Utah (PSCU) order effective June 1, 2006. Costs incurred prior to June 2006 were deferred and will now be recovered over a three-year period. Actual current costs in excess of $1.4 million annually will be deferred and recovered in future rates.

Note 11 – 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 $200 million of 7% Notes due 2007. Market Resources recorded a $1.7 million pre-tax charge related to the early extinguishment.

Note 12 – Questar Gas Rate Changes

In October 2006, the PSCU approved a pilot program for a “conservation enabling tariff” (CET) effective January 1, 2006, to promote energy conservation. The company’s prior rate structure penalized the company for declining usage per customer and rewarded the company for increasing usage per customer. Under the CET, Questar Gas non-gas revenues are decoupled from the volume of gas used by customers. The tariff specifies a margin per customer for each month with differences to be deferred and recovered from customers or refunded to customers through periodic rate adjustments. These adjustments will be limited to one percent of total revenues for the first year. The program will be reviewed after one

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year. Questar Gas recorded a $0.6 million revenue reduction in the third quarter of 2006 to recognize the impact of the CET. Questar Gas will propose energy efficiency programs to reduce customers’ natural gas consumption.

Effective June 1, 2006, the PSCU approved a settlement of other issues and ordered 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.

Note 13 – 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		9 Months Ended
	September 30,		September 30,
	2006	2005	2006	2005
		(in thousands)

Net income	$ 95,056	$ 65,757	$322,574	$221,655
Other comprehensive income (loss)
Net unrealized gain (loss) on hedging contracts	196,613	(352,386)	479,895	(500,204)
Income taxes	(74,367)	133,237	(181,715)	189,467
Net other comprehensive income (loss)	122,246	(219,149)	298,180	(310,737)
Total comprehensive income (loss)	$217,302	($153,392)	$620,754	($89,082)

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

	September 30,	December 31,
	2006	2005	Change
	(in thousands)

Net unrealized gain (loss) on hedging contracts	$100,078	($198,102)	$298,180
Additional pension liability	(21,176)	(21,176)
Accumulated other comprehensive income (loss)	$ 78,902	($219,278)	$298,180

Note 14 – Recent Accounting Development

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation 48 “Accounting for Uncertainty in Income Taxes” (FIN 48). The interpretation applies to all tax positions related to income taxes subject to FASB Statement 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 an y, that FIN 48 will have on its financial statements.

On September 29, 2006, the FASB issued SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”. The new accounting standard reconsidered the

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over or under funded status of its defined-benefit plans on the balance sheet effective with its annual report on Form 10-K for the year ending December 31, 2006. The over or under funded defined-benefit pension position will be measured by the difference in the fair value of plan assets and the projected benefit obligation. The projected benefit obligation includes an estimate of future salary changes. The over or under funded other postretirement benefit position will be measured by the difference in the fair value of plan assets and the accumulated benefit obligation. SFAS 158 changes how pension and other postretirement assets and liabilities are measured and the timing of when the changes are recognized in the statement of income. The Company is currently evaluating the impact of SFAS 158.

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

The following discussion updates information as to Questar’s financial condition provided in its previous Form 10-Q and 10-K filings, and analyzes the changes in the results of operations between the three- and nine-month periods ended September 30, 2006 and 2005. For definitions of commonly used gas and oil terms found in this Form 10-Q, please refer to the “Glossary of Commonly Used Terms” provided in the 2005 Annual Report on Form 10-K.

Summary

Questar grew net income 45% in the third quarter of 2006 to $95.1 million or $1.08 per diluted share, compared to $65.8 million or $0.75 per diluted share, for the third quarter of 2005. Third quarter 2006 results included a $15.8 million or $0.18 per diluted share after-tax gain from the sale of assets, an $8.7 million or $0.10 per diluted share after-tax charge related to unsuccessful exploratory wells in Wyoming and Utah and a $3.2 million or $0.04 per diluted share after-tax charge for mark-to-market losses on natural gas basis-only swaps. Net income growth was driven by higher natural gas production and higher realized prices for natural gas, oil and NGL.

For the first nine months of 2006, Questar net income was $322.6 million, or $3.68 per diluted share compared to $221.7 million or $2.55 per diluted share for the 2005 period, a 46% increase. Following are comparisons of net income by line of business:

	3 Months Ended			9 Months Ended
	September 30,		%	September 30,			%
	2006	2005	Change	2006		2005	Change
	(in millions, except per share amounts)
Net income (loss)
Market Resources
Questar E&P	$66.0	$44.8	47%		$192.6	$115.4	67%
Wexpro	12.1	11.3	7	36.1		31.9	13
Gas Management	11.0	7.3	51	30.9		25.1	23
Energy Trading and other	2.9	1.9	53	6.4		4.3	49
Market Resources total	92.0	65.3	41	266.0		176.7	51

Questar Pipeline	10.1	9.2	10	31.5		25.2	25
Questar Gas	(9.2)	(9.9)	7	19.5		15.4	27
Corporate and other operations	2.2	1.2	83		5.6	4.4	27
Questar Corporation total	$95.1	$65.8	45%		$322.6	$221.7	46%
Earnings per diluted share	$1.08	$ 0.75			$ 3.68	$ 2.55
Average diluted shares	87.7	87.4			87.6	87.0

Market Resources net income was 41% higher in the third quarter of 2006 and 51% higher for the first nine months of 2006 compared to the same periods of 2005. Higher natural gas production and higher realized prices for natural gas, oil and NGL, higher gas processing and gas gathering margins and an

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increased investment base for Wexpro drove the increase. Third quarter 2006 results also included a $15.8 million after-tax gain from the sale of assets, an $8.7 million after-tax charge related to unsuccessful exploratory wells in Wyoming and Utah and a $3.2 million after-tax charge for mark-to-market losses on natural gas basis-only swaps.

Questar Pipeline net income grew 10% in the third quarter and 25% in the first nine months 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 7% in the third quarter of 2006, while net income for the first nine months of 2006 increased 27% compared with the 2005 periods. Third quarter 2006 results reflect continued customer growth and lower bad debt and depreciation expenses. In June 2006, Questar Gas implemented lower customer rates, primarily due to reduced depreciation rates. Due to the seasonal nature of Questar Gas revenues, the change in customer rates and depreciation expense increased third quarter 2006 net income by $1.0 million. This seasonal shift is expected to reverse in the fourth quarter of 2006. The 2006 results also benefited from the recovery of $3.6 million gas-processing costs 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 $92.0 million of net income for the third quarter of 2006 compared with $65.3 million for the year earlier period, a 41% increase. Net income for the first nine months of 2006 totaled $266.0 million versus $176.7 million for the same period in 2005, a 51% increase. Operating income increased $24.5 million, or 23%, in the quarter to quarter comparison, and $132.0 million, or 45%, in the nine 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 third quarter and first nine months of 2006 compared with the same periods of 2005:

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2006	2005	2006	2005
		(in thousands)
OPERATING INCOME
Revenues
Natural gas sales	$168,725	$131,466	$ 512,799	$ 352,985
Oil and NGL sales	41,997	31,254	114,963	86,178
Cost-of-service gas operations	36,588	32,051	111,048	97,704
Energy marketing	174,950	248,069	484,214	568,979
Gas gathering, processing and other	45,632	38,652	136,656	108,705
Total revenues	467,892	481,492	1,359,680	1,214,551
Operating expenses
Energy purchases	169,999	243,972	473,422	559,201
Operating and maintenance	44,444	42,222	132,034	110,872
General and administrative	18,211	13,332	50,270	41,037
Production and other taxes	21,991	25,413	70,045	67,619

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Depreciation, depletion and amortization	61,766	44,083	169,401	125,199
Exploration	16,847	2,574	30,247	9,423
Abandonment and impairment of gas, oil and other properties	1,955	1,712	5,497	4,610
Wexpro Agreement – oil-income sharing	1,728	1,770	4,542	4,395
Total operating expenses	336,941	375,078	935,458	922,356
Operating income	$130,951	$106,414	$ 424,222	$ 292,195

OPERATING STATISTICS
Questar E&P production volumes
Natural gas (MMcf)	29,424	25,681	85,541	71,930
Oil and NGL (Mbbl)	729	593	1,972	1,762
Total production (Bcfe)	33.8	29.2	97.4	82.5
Average daily production (MMcfe)	367	318	357	302
Questar E&P average realized price, net to the well (including hedges)
Natural gas (per Mcf)	$ 5.73	$ 5.12	$ 5.99	$ 4.91
Oil and NGL (per bbl)	$ 49.81	$ 43.04	$ 50.10	$ 40.61
Wexpro investment base at September 30, net
of depreciation and deferred income taxes (millions)	$ 224.8	$ 197.6
Natural gas processing volumes
NGL sales volumes (Mgal)	20,778	24,562	65,322	64,846
Processing fee based (in thousands of MMBtu)	30,552	19,546	87,108	43,476
Natural gas processing revenues
NGL sales price (per gal)	$ 0.89	$ 0.73	$ 0.89	$ 0.71
Processing fee based (per MMBtu)	$ 0.13	$ 0.16	$ 0.14	$ 0.16
Natural gas gathering volumes (in thousands of MMBtu)
For unaffiliated customers	41,341	35,619	109,775	101,693
For Questar Gas	9,970	10,252	30,212	32,734
For other affiliated customers	20,831	17,895	55,824	48,157
Total gathering	72,142	63,766	195,811	182,584
Gathering revenue (per MMBtu)	$ 0.28	$ 0.25	$ 0.29	$ 0.25
Natural gas and oil marketing volumes (Mdthe)
For unaffiliated customers	29,320	32,064	84,607	87,320
For affiliated customers	24,938	22,455	74,816	67,102
Total marketing	54,258	54,519	159,423	154,422

Questar E&P

Questar E&P, a Market Resources subsidiary that conducts natural gas and oil exploration, development and production, reported net income of $66.0 million in the third quarter, up 47% from $44.8 million in the 2005 quarter. Net income for the first nine months of 2006 was $192.6 million versus $115.4 million for the same period of 2005, a 67% 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 33.8 Bcfe in the third quarter of 2006, a 16% increase compared to the year-earlier period. Production for the first nine months of 2006 was 97.4

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comprised approximately 87% of Questar E&P production for the third quarter of 2006. A comparison of natural gas-equivalent production by region is shown in the following table:

	3 Months Ended				9 Months Ended
	September 30,			%	September 30,			%
	2006	2005		Change	2006*	2005		Change
	(Bcfe)				(Bcfe)

Pinedale Anticline	10.9		8.7	25%	28.8		22.8	26%
Uinta Basin	6.5		6.6	(2)	18.9		19.2	(2)
Rockies Legacy	4.5		4.3	5	14.5		12.3	18
Subtotal – Rocky Mountains	21.9		19.6	12	62.2		54.3	15
Midcontinent	11.9		9.6	24	35.2		28.2	25
Total Questar E&P	33.8		29.2	16%	97.4		82.5	18%

*Includes 0.7 Bcfe related to settlement of an imbalance in Rockies Legacy. Without the one-time adjustment, total Questar E&P production grew 17%.

Questar E&P production from the Pinedale Anticline in western Wyoming grew 26% to 28.8 Bcfe in the first nine months of 2006 and comprised 30% of Questar E&P total production in the 2006 period. Production at Pinedale declines early in the 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. Production at Pinedale was 8.2 Bcfe in the second quarter of 2006 and 9.7 Bcfe in the first quarter of 2006.

In the Uinta Basin of eastern Utah, Questar E&P production decreased 2% to 18.9 Bcfe in the first nine months of 2006 compared to a year ago. Third quarter production of 6.5 Bcfe was up slightly compared to the 6.2 Bcfe recorded in both the second and first quarters of 2006.

Production from Questar E&P Rocky Mountain “Legacy” properties increased 18% to 14.5 Bcfe in the first nine months of 2006 compared to a year ago. Excluding a one-time adjustment, Legacy production for the first nine months of 2006 was 13.8 Bcfe, an increase of 12% 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 25% to 35.2 Bcfe in the first nine 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 1.7 Bcfe and has averaged 5.4 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 nine months of 2006, the weighted average realized natural gas price for Questar E&P (including the impact of hedging) was $5.99 per Mcf compared to $4.91 per Mcf for the same period in 2005, a 22% increase. Realized oil and NGL prices for the first nine months of 2006 averaged $50.10 per bbl, compared with $40.61 per bbl during the prior year period, a 23% increase. A regional comparison of average realized prices, including hedges, is shown in the following table:

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	3 Months Ended			9 Months Ended
	September 30,		%	September 30,			%
	2006	2005	Change	2006		2005	Change

Natural gas (per Mcf)
Rocky Mountains	$ 5.38	$ 4.94	9%	$ 5.68	$ 4.73		20%
Midcontinent	6.36	5.47	16	6.54	5.23		25
Volume-weighted average	$ 5.73	$ 5.12	12%	$ 5.99	$ 4.91		22%

Oil and NGL (per bbl)
Rocky Mountains	$46.59	$44.13	6%	$47.88	$41.38		16%
Midcontinent	57.68	40.34	43	55.28	38.84		42
Volume-weighted average	$49.81	$43.04	16%	$50.10	$40.61		23%

Approximately 69% and 68% of Questar E&P gas production in the third quarter and nine months of 2006, respectively, was hedged or pre-sold. Hedging increased gas revenues $18.3 million and $21.0 million during the third quarter and first nine months of 2006, respectively. Approximately 76% and 78% of Questar E&P oil production in the third quarter and nine months of 2006, respectively, was hedged or pre-sold. Oil hedges reduced revenues $6.7 million and $17.1 million during the third quarter and first nine 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 third 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 uses basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials that may result from capacity constraints on regional gas pipelines. Derivative positions as of September 30, 2006, are summarized in Part I, Item 3 of this quarterly report.

Questar E&P production costs (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense, allocated-interest expense and production taxes) per Mcfe of production increased 5% to $2.97 per Mcfe compared to the third quarter of 2005. For the first nine months of 2006, production costs rose 5% to $2.90 per Mcfe. Questar E&P production costs are summarized in the following table:

	3 Months Ended			9 Months Ended
	September 30,		%	September 30,		%
	2006	2005	Change	2006	2005	Change
	(Per Mcfe)			(Per Mcfe)

Depreciation, depletion and amortization	$1.43	$1.19	20%	$1.37	$1.17	17%
Lease operating expense	0.56	0.52	8	0.55	0.55
General and administrative expense	0.34	0.29	17	0.32	0.31	3
Allocated interest expense	0.19	0.21	(10)	0.21	0.21
Production taxes	0.45	0.61	(26)	0.45	0.53	(15)
Total production costs	$2.97	$2.82	5%	$2.90	$2.77	5%

Depreciation, depletion and amortization expense rose 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 unit lease operating expense increased due to increased costs of materials and consumables and higher well workover costs. General and administrative expenses increased due to higher labor costs and an increase in the allowance for doubtful accounts.

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Interest expense per unit decreased in the 2006 quarter due to refinancing of long-term debt at a lower interest rate and higher production volumes. Production taxes per unit decreased with lower sales prices on natural gas, increased incentive tax credits related to well drilling and production enhancement projects, and adjustments to prior estimates.

Questar E&P’s exploration expense increased $14.3 million in the third quarter 2006 and $21.2 million in the first nine months compared to the 2005 periods. The increases were due to expenses for unsuccessful exploratory wells in Wyoming and Utah. Abandonment and impairment expense increased $0.2 million for the third quarter 2006 and $0.9 million for the first nine months of 2006.

Pinedale Anticline

As of September 30, 2006, Market Resources (both Questar E&P and Wexpro) operated and had working interest in 178 producing wells on the Pinedale Anticline compared to 127 at the end of the third quarter of 2005. Of the 178 producing wells, Questar E&P has working interests in 158 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 178 producing wells. Market Resources expects to complete between 48 and 51 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 nine months of 2006, the company drilled or participated in 39 Wasatch and Upper Mesaverde gas wells, three horizontal and two vertical Green River Formation oil wells, and three deeper Blackhawk, Mancos and Dakota formations gas wells on its core acreage block.

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 September 30, 2006, the company had recompleted two older wells, drilled and completed 10 new wells, and two were waiting on completion. 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 14,000 feet.

Midcontinent

During the third quarter the company continued a two-rig infill-development project in the Elm Grove field in northwest Louisiana as it drilled or participated in 12 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 provides Questar E&P initial or additional working interest in approximately 75 undrilled locations.

Wexpro

Wexpro, a Market Resources subsidiary that develops and produces cost-of-service reserves for Questar Gas, reported net income was $12.1 million, in the third quarter of 2006 compared with $11.3 million for the same period in 2005, a 7% increase. For the first nine months of 2006 Wexpro net income was $36.1 million, compared with $31.9 million for the same period in 2005, a 13% 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

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working capital and reduced for deferred income taxes and depreciation (investment base). Wexpro investment base at September 30, 2006, was $224.8 million, an increase of $27.2 million or 14%.

Gas Management

Gas Management, Market Resources gas-gathering and processing-services business, grew net income 51% to $11.0 million in the third quarter of 2006 from $7.3 million in the 2005 period. Net income for the first nine months of 2006 was $30.9 million versus $25.1 million for the same period in 2005, a 23% increase. Gas processing plant margin grew 79% from $16.9 million in the first nine months of 2005 to $30.3 million in the first nine months of 2006. Gathering volumes increased 13.2 million MMBtu to 195.8 million MMBtu in the first nine months of 2006 due primarily to expanding Pinedale production and new projects serving third parties in the Uinta Basin. Total gathering margins increased 5% despite increased 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 nine months of 2006, revenues from keep-whole contracts benefited from a 24% increase in realized NGL sales prices versus the prior-year period. Revenues from fee-based contracts were impacted by a 100% increase in processing volumes offset by a $0.03 decrease in the average rate charged per MMBtu processed in the first nine months 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 decreased NGL revenues by $0.8 million in 2006.

Income before income tax from Gas Management’s 50% interest in Rendezvous Gas Services, LLC, (Rendezvous), a joint venture that operates gas-gathering facilities in western Wyoming, was $5.0 million for the first nine months of 2006, the same as the year earlier period. 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 third quarter of 2006 of $2.9 million compared to $1.9 million in 2005, a 53% increase. For the first nine months of 2006, net income was $6.4 million compared to $4.3 million for the same period in 2005, a 49% increase. Service fee revenues from affiliates were $0.1 million lower in the third quarter of 2006 and $0.8 million higher in the first nine 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 $10.8 million for the first nine months of 2006 versus $9.8 million a year ago, a 10% increase. The increase in gross margin was due primarily to a 3% increase in volumes and increased storage activity over the same period last year.

Questar Pipeline

Questar Pipeline, which provides interstate natural gas-transportation and storage services, reported net income of $10.1 million for the third quarter of 2006 compared with $9.2 million in the third quarter of 2005. Questar Pipeline net income for the first nine months of 2006 was $31.5 million compared with $25.2 million 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 third quarter and first nine months of 2006 compared with the same periods of 2005:

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	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2006	2005	2006	2005
		(in thousands)
OPERATING INCOME
Revenues
Transportation	$ 29,761	$26,643	$ 89,411	$ 79,897
Storage	9,346	9,156	28,225	27,986
Gas processing	1,447	1,405	4,238	4,872
NGL and other revenues	4,339	5,562	13,766	10,952
Total revenues	44,893	42,766	135,640	123,707
Operating expenses
Operating and maintenance	8,470	7,002	24,631	22,592
General and administrative	4,530	6,520	14,244	18,398
Depreciation and amortization	7,847	7,340	23,595	21,853
Other taxes	2,108	1,686	5,573	4,943
Total operating expenses	22,955	22,548	68,043	67,786
Operating income	$ 21,938	$20,218	$ 67,597	$ 55,921

OPERATING STATISTICS
Natural gas transportation volumes (in Mdth)
For unaffiliated customers	88,115	71,257	228,991	188,252
For Questar Gas	14,936	16,594	83,074	86,545
For other affiliated customers	7,255	9,072	16,829	17,553
Total transportation	110,306	96,923	328,894	292,350
Transportation revenue (per dth)	$ 0.27	$ 0.27	$ 0.27	$ 0.27
Firm-daily transportation demand at September 30 (Mdth)	2,151	1,832

Revenues

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

	3 Months Ended Sept. 30, 2006 Compared with 2005	9 Months Ended Sept. 30, 2006 Compared with 2005
	(in thousands)
Transportation
New transportation contracts	$ 3,943	$12,347
Expiration of transportation contracts	(338)	(1,447)
Other transportation	(487)	(1,386)
Storage	190	239
Gas processing	42	(634)
NGL and other revenues
Change in NGL revenues	(1,506)	1,709
Change in gathering revenues	61	278
Park and loan revenues	262	912
Other	(40)	(85)
Increase	$ 2,127	$11,933

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As of September 30, 2006, Questar Pipeline had firm-transportation contracts of 2,151 Mdth per day compared with 1,832 Mdth per day as of September 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 in service an interconnection with Kern River Gas Transmission Company that 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 transportation contract extend 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 two to 13 years and 100% of the firm-storage capacity at the aquifer facilities for terms extending for 12 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 first nine months of 2006 over the same period of 2005. NGL revenues were lower in the third quarter of 2006 compared with the third quarter of 2005 due to the 2005 resolution of the fuel-gas reimbursement percentage proceedings as discussed below. NGL volumes increased 2% in the third quarter and 43% in the first nine months of 2006, and NGL prices increased 37% in the third quarter and 36% in the first nine months of 2006 compared to the prior year periods.

Revenues from park and loan services increased in the first nine months of 2006 over the first nine months 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 third quarter of 2005, Questar Pipeline received approval of a settlement with customers that resolved outstanding issues in the 2004 and 2005 FGRP filings. Included in this settlement was a resolution of the amount of liquid revenues at the Kastler plant to be retained by Questar Pipeline. 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 $0.5 million in the third quarter of 2006 and $2.1 million in the first nine months 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 40% of the decrease. Operating, maintenance, general and administrative expenses per decatherm transported declined from $0.14 in the first nine months of 2005 to $0.12 in the first nine months of 2006.

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Depreciation expense increased 7% in the third quarter of 2006 and 8% in the first nine months 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 cumulative gas loss is due to imprecision inherent in measurement of large injection and withdrawal volumes as well as reservoir heterogeneity that impacts storage reservoir performance. The cushion gas loss represents 0.25 % of the volume of gas cycled in and out of the reservoir over the past 30 years. 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. This accounting treatment 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 Pipeline is discussing various tariff changes including a resolution of this issue with firm storage customers.

Questar Gas

Questar Gas, which provides natural gas distribution services in Utah, Wyoming and Idaho, reported a seasonal net loss of $9.2 million in the third quarter of 2006 compared with a net loss of $9.9 million in the third quarter of 2005. Questar Gas net income was $19.5 million in the first nine months of 2006 compared with $15.4 million in the first nine months 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 third quarter and first nine months of 2006 compared with the same periods of 2005:

	3 Months Ended		9 Months Ended
	September 30,		September 30,
	2006	2005	2006	2005
		(in thousands)
OPERATING INCOME
Revenues
Residential and commercial sales	$ 86,499	$ 87,849	$690,390	$541,632
Industrial sales	2,620	9,873	20,626	28,974
Transportation for industrial customers	1,565	1,321	4,571	4,226
Other	10,019	12,301	36,722	33,876
Total revenues	100,703	111,344	752,309	608,708
Cost of natural gas sold	72,649	81,042	581,757	444,998
Margin	28,054	30,302	170,552	163,710
Operating expenses
Operating and maintenance	16,664	17,998	55,062	53,869
General and administrative	10,237	9,480	30,596	30,526
Depreciation and amortization	8,951	11,875	31,116	34,073

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Other taxes	3,475	3,468	10,809	9,932
Total operating expenses	39,327	42,821	127,583	128,400
Operating income (loss)	($ 11,273)	($ 12,519)	$ 42,969	$ 35,310

OPERATING STATISTICS
Natural gas volumes (in Mdth)
Residential and commercial sales	8,751	9,081	67,708	65,843
Industrial sales	362	1,348	2,639	4,445
Transportation for industrial customers	9,560	7,218	25,429	22,941
Total deliveries	18,673	17,647	95,776	93,229
Natural gas revenue (per dth)
Residential and commercial sales	$ 9.88	$ 9.67	$ 10.20	$ 8.23
Industrial sales	7.23	7.32	7.82	6.52
Transportation for industrial customers	$ 0.16	$ 0.18	$ 0.18	$ 0.18
Heating degree days – colder (warmer) than normal	69%	16%	(5%)	(2%)
Average temperature adjusted usage
per customer (dth)	7.9	8.8	76.4	76.9
Customers at September 30,	835,025	803,196

Margin Analysis

Questar Gas margin (revenues less gas costs) decreased $2.2 million in the third quarter and increased $6.8 million in the first nine months of 2006 compared to the same periods of 2005. Following is a summary of major changes in Questar Gas margin:

	3 Months Ended Sept. 30, 2006 Compared with 2005	9 Months Ended Sept. 30, 2006 Compared with 2005
	(in thousands)

New customers	$ 473	$ 4,569
Conservation enabling tariff adjustment	(640)	(640)
Gas processing revenues collected from customers	999	3,604
Change in rates	(804)	(1,360)
Recovery of bad debt gas costs	(1,166)	(363)
Change in unbilled estimate	(2,329)	(2,329)
Other	1,219	3,361
Increase (decrease)	($2,248)	$ 6,842

Temperature-adjusted usage per customer was down 10% in the third quarter and 1% in the first nine months of 2006 compared to the same periods of 2005. The impact on the company’s margin from changes in usage per customer has been mitigated by a conservation enabling tariff that was approved by the PSCU in October 2006. Questar Gas recorded a reduction in margin of $0.6 million in the third quarter of 2006 to reflect the impact of changes in usage per customer for the 2006 year-to-date period. See Part I, Item 1. Note 12 for a discussion of the conservation enabling tariff.

Effective June 1, 2006, Utah customer rates were reduced by $9.7 million per year, primarily to reflect changes in the company’s depreciation rates. Due to typically low customer usage in the third quarter, the effect of the reduced tariff had little impact on revenues; however, lower depreciation rates

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caused expenses to decline and resulted in a $1.0 million increase in net income. This effect is expected to reverse with higher usage in the fourth quarter. See Note 12 for a discussion of the rate changes.

Weather, as measured in degree days, was 69% colder than normal in the third quarter of 2006 compared with 16% colder than normal in the third quarter of 2005. For the first nine months of 2006, weather was 5% warmer than normal compared with 2% warmer than normal in 2005. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations. At September 30, 2006, Questar Gas was serving 835,025 customers, up from 824,447 at December 31, 2005.

Industrial deliveries (including sales and transportation) increased 16% in the third quarter of 2006 and 2% in the first nine months of 2006 compared to 2005.

As discussed below, Questar Gas received rate coverage for gas-processing costs in the third quarter of 2006 of $1.0 million and the first nine months of 2006 of $3.6 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.

Expenses

Cost of natural gas sold decreased 10% in the third quarter of 2006 and increased 31% in the first nine months of 2006 compared with 2005 periods due primarily to changes in gas purchase expenses 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 September 30, 2006, Questar Gas had a $29.3 million over collection balance in the purchased-gas adjustment account representing costs recovered from customers in excess of costs incurred. In November 2005, rates were increased significantly to recover increased gas costs caused by the Gulf Coast hurricanes. Questar Gas reduced rates in Utah and Wyoming effective November 1, 2006, by more than the prior year increases.

Operating, maintenance, general and administrative expenses decreased 2% in the third quarter of 2006 and increased 1% in the first nine months of 2006 compared to 2005 periods. Bad debt costs were lower in the 2006 periods due to increased collections. Operating, maintenance, general and administrative expenses per customer were $103 in the first nine months of 2006 compared with $105 in the first nine months of 2005.

Depreciation expense decreased 25% in the third quarter of 2006 and 9% in the first nine months of 2006 compared to 2005 periods. As explained in Part I, Item 1. Financial Statements Note 12, Questar Gas reduced its depreciation rates effective June 1, 2006, in accordance with a PSCU order. This offsets 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 12 for a discussion of the Conservation Enabling Tariff and a rate reduction in Utah.

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Consolidated Results after Operating Income

Net gain on asset sales

During the third quarter Market Resources subsidiaries sold properties, primarily in western Colorado, and recognized pre-tax gains totaling $25.3 million. For the nine months ended September 30, 2006, pre-tax gains on asset sales totaled $25.5 million.

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 income tax decreased by $0.2 million in the third quarter of 2006 and was unchanged in the first nine months of 2006 compared with the 2005 periods. Rendezvous gathering volumes decreased 2% in the third quarter of 2006 and increased 2% in the first nine months of 2006 compared to the year earlier periods.

Interest expense and loss on early extinguishment of debt

Interest expense rose in the first nine months of 2006 due primarily to increased average debt levels between the two nine month periods and higher interest rates on short-term debt outstanding in the early part of 2006. Market Resources recognized a $1.7 million pre-tax loss on the early extinguishment of its 7% Notes due 2007.

Net unrealized mark-to-market loss on basis swaps

The Company uses basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials that may result from capacity constraints on regional gas pipelines. The Company recorded unrealized mark-to-market losses of $5.1 million and $10.8 million on the NYMEX/Rockies basis swaps in the third quarter and nine months of 2006, respectively.

Income taxes

The effective combined federal and state income tax rate was 37.0% in the first nine months of 2006 compared with 36.9% in the 2005 period.

Liquidity and Capital Resources

Operating Activities

	9 Months Ended
	September 30,
	2006	2005
	(in thousands)

Net income	$322,574	$ 221,655
Noncash adjustments to net income	294,919	262,769
Changes in operating assets and liabilities	116,499	(179,313)
Net cash provided from operating activities	$733,992	$ 305,111

Net cash provided from operating activities increased 141% in the first nine months of 2006 compared to the same period last year because of higher net income and lower derivative collateral deposits. Derivative collateral deposits were zero at September 30, 2006, compared with $243.3 million at September 30, 2005, as a result of lower commodity prices, the elimination of credit support requirements with several counterparties, increases in the amount of credit allowed by other counterparties before Market Resources is required to deposit collateral and the normal monthly settlement of hedge contracts.

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Investing Activities

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

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

Market Resources	$503,637	$380,137	$731,100
Questar Pipeline	31,787	56,643	100,500
Questar Gas	68,180	49,991	99,100
Corporate and other operations	437	1,140	700
Total	$604,041	$487,911	$931,400

Expanded drilling programs represented the majority of the increase in capital expenditures for the first nine 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 distribute $59.5 of dividends in the first nine months 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 33% of total capital at September 30, 2006. At September 30, 2006, the Company had $450 million of short-term lines of credit available and Market Resources had an unused $182 million long-term revolving-credit facility with banks.

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, 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

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Resources does not enter into derivative arrangements for speculative purposes and does not hedge undeveloped reserves or Questar E&P equity NGL.

Market Resources uses fixed-price swaps to manage natural gas, oil and NGL price risk. A fixed-price swap is a derivative instrument that exchanges or “swaps” the “floating” or daily price of a specified volume of natural gas, oil or NGL, over a specified period, for a fixed price for the specified volume over the same period. In the normal course of business, the Company sells its equity natural gas, oil and NGL production to third parties at first-of-the-month or daily “floating” prices related to indices reported in industry publications. To reduce exposure to highly volatile daily and monthly commodity prices, the Company uses a derivative instrument that exchanges or “swaps” the “floating” or daily price of the commodity for a fixed-price for the specified period (typically for periods of three months or longer). The Company enters into these transactions with banks and industry counterparties with investment-grade credit ratings. Swap agreements do not require the physical transfer of gas between the parties at settlement. Swap transactions are settled monthly, in cash, with one party paying the other for the net difference in prices, multiplied by the relevant volume, for the settlement period.

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.

Market Resources also entered into natural gas basis-only swaps in 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 $182 million long-term revolving-credit facility with banks with no borrowings outstanding at September 30, 2006.

A summary of Market Resources derivative positions for equity production as of September 30, 2006, is shown below. Currently fixed-price and basis-only swaps are with creditworthy counterparties. 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
Fourth Quarter	15.6	6.1	21.7	$6.04	$6.81	$6.26

2007
First half	21.5	15.4	36.9	$6.93	$7.81	$7.30
Second half	21.8	15.6	37.4	6.93	7.81	7.30
12 months	43.3	31.0	74.3	6.93	7.81	7.30

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2008
First half	16.9	12.2	29.1	$7.19	$7.98	$7.52
Second half	17.9	12.3	30.2	7.16	7.98	7.49
12 months	34.8	24.5	59.3	7.18	7.98	7.51

2009
First half	6.7	5.2	11.9	$7.01	$7.68	$7.30
Second half	6.8	5.3	12.1	7.01	7.68	7.30
12 months	13.5	10.5	24.0	7.01	7.68	7.30

	Gas (in Bcf) Basis-Only Swaps			Estimated Average basis per Mcf vs. NYMEX
2006
Fourth quarter	2.6		2.6	$2.13		$2.13

2007
First half	8.4		8.4	$1.92		$1.92
Second half	8.6		8.6	1.92		1.92
12 months	17.0		17.0	1.92		1.92

2008
First half	13.6		13.6	$1.60		$1.60
Second half	13.7		13.7	1.60		1.60
12 months	27.3		27.3	1.60		1.60

2009
First half	1.7		1.7	$0.95		$0.95
Second half	1.7		1.7	0.95		0.95
12 months	3.4		3.4	0.95		0.95

	Oil (in Mbbl) Fixed-Price Swaps			Average price per bbl, net to the well
2006
Fourth Quarter	313	101	414	$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

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As of September 30, 2006, Market Resources held commodity-price hedging contracts covering about 207.0 million MMBtu of natural gas, 2.2 MMbbl of oil and 31.5 million gallons of NGL. A year earlier Market Resources hedging contracts covered 182.3 million MMBtu of natural gas, 2.6 MMbbl of oil and 14.1 million gallons of NGL. Market Resources has also entered into basis-only swaps on an additional 50.3 million MMBtu of natural gas. There were no basis-only swaps a year earlier.

Questar Gas has entered into a fixed-price swap in the third quarter of 2006 to lock-in the purchase price of 6.0 Bcf of natural gas during the 2006/2007 heating season. The fair value of this fixed-price swap was a $6.8 million liability at September 30, 2006, and is included in the tables below.

The following table summarizes changes in the fair value of derivative contracts from December 31, 2005 to September 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	157,170		157,170
Change in gas and oil prices on futures markets	229,486		229,486
Contracts added since December 31, 2005	86,351	($10,564)	75,787
Net fair value of gas- and oil-derivative contracts outstanding at September 30, 2006	$153,886	($10,564)	$143,322

A table of the net fai r value of gas- and oil-derivative contracts as of September 30, 2006, is shown below. About 64% 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 September 30, 2007	$ 96,243	($ 4,735)	$ 91,508
Contracts maturing between October 1, 2007 and September 30, 2008	41,517	(3,999)	37,518
Contracts maturing between October 1, 2008 and September 30, 2009	15,000	(1,686)	13,314
Contracts maturing after September 30, 2009	1,126	(144)	982
	$153,886	($10,564)	$143,322

The following table shows sensitivity of fair value of gas and oil derivative contracts and basis-only swaps to changes in the market price of gas and oil and basis differentials:

	At September 30,
	2006	2005
	(in millions)

Net fair value – asset (liability)	$143.3	($568.1)
Value if market prices of gas and oil and basis differentials decline by 10%	291.3	(403.6)
Value if market prices of gas and oil and basis differentials increase by 10%	9.0	(732.6)

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Interest-Rate Risk Management

As of September 30, 2006, Questar had $1,032.4 million of fixed-rate long-term debt and no variable rate debt.

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.

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.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Questar is involved in various commercial and regulatory claims and litigation and other legal proceedings that arise in the ordinary course of its business. Management does not believe any of them will have a material adverse effect on Questar’s financial position. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. Some of the claims involve highly complex issues relating to liability, damages and other matters subject to substantial uncertainties and, therefore, the probability of liability or an estimate of loss cannot be reasonably determined.

Grynberg. Questar affiliates are involved in various pending lawsuits filed by Jack Grynberg, an independent producer. In United States ex rel. Grynberg v. Questar Corp., Civil No. 99-MD-1604, consolidated as In re Natural Gas Royalties Qui Tam Litigation, Consolidated Case MDL No. 1293 (D. Wyo.), Grynberg has filed qui tam claims against Questar under the federal False Claims Act substantially similar to other cases filed against other industry pipelines and their affiliates which have been consolidated for discovery and pre-trial motions in Wyoming’s federal district court. The cases involve allegations of industry-wide mismeasurement of natural gas quantities on which royalty payments are due the federal government.

The defendants filed a motion contending that the court has no jurisdiction over the case because Grynberg cannot satisfy the statutory requirements for jurisdiction. The defendants argued that Grynberg’s allegations were publicly disclosed prior to the filing of his complaint and that Grynberg is not the “original source” of the information on which the allegations are based. The Special Master appointed in the case issued a Report and Recommendation to the district court recommending dismissal of the Questar defendants, except for one small entity acquired by Questar Gas after these cases were filed. By order dated October 20, 2006, the district court granted defendants motion and dismissed all of Grynberg’s claims against all the defendants for lack of jurisdiction. The judge found that Grynberg was not the “original source” and therefore could not bring the action. Grynberg will likely file a notice of appeal.

In Grynberg and L & R Exploration Venture v. Questar Pipeline Co., Civil No. 97CV0471 (D. Wyo.) Grynberg brought breach of contract claims, statutory claims and fraud claims against Questar entities related to a certain gas purchase contract for the purchase of gas produced from wells located in Wyoming. In June 2001 the federal district judge entered an order granting partial summary judgment dismissing the antitrust claims from the case. By order dated September 12, 2006, the judge also dismissed the fraud claims and ratable-take claims. The breach of contract claims are the only issues remaining to be decided. Grynberg filed a notice of appeal on October 11, 2006.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

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

July 1, 2006 –

July 31, 2006

17,331

$87.44

August 1, 2006 –

August 31, 2006

22,518

$89.45

-33-


September 1, 2006 – September 30, 2006	1,035	$85.15	-	-

Total	40,884	$88.49	-	-

*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 Div idend Reinvestment and Stock Purchase Plan and any shares of restricted stock forfeited when failing to satisfy vesting conditions.

Item 6. Exhibits

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

Exhibit No.

Exhibits

10.1.

Questar Corporation Deferred Compensation Wrap Plan, as adopted on October 24, 2006.

31.1.

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

31.2.

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

32.

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

SIGNATURES

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

QUESTAR CORPORATION

(Registrant)

November 3, 2006

/s/Keith O. Rattie

Keith O. Rattie, Chairman of the Board,

President and Chief Executive Officer

November 3, 2006

/s/S. E. Parks

S. E. Parks, Senior Vice President and

Chief Financial Officer

-34-

Exhibits List

Exhibits

10.1.

Questar Corporation Deferred Compensation Wrap Plan, as adopted on October 24, 2006.

31.1.

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

31.2.

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

32.

Exhibit 10.1

QUESTAR CORPORATION

DEFERRED COMPENSATION WRAP PLAN

incorporating the:

Deferred Compensation Program

401(k) Supplemental Program

Effective January 1, 2005

QUESTAR CORPORATION

DEFERRED COMPENSATION WRAP PLAN

(Effective January 1, 2005)

ARTICLE 1

INTRODUCTION

1.1

Purpose. Questar Corporation hereby establishes this DEFERRED COMPENSATION WRAP PLAN (the “Plan” or “Wrap Plan”) effective January 1, 2005, in order to provide specified benefits to a select group of management and highly compensated employees and to allow such employees to defer the receipt of compensation. The Plan consists of a main Deferred Compensation Wrap Plan and two component Programs – the Deferred Compensation Program and the 401(k) Supplemental Program (each as described below). The Wrap Plan contains overriding participation, election, and administrative rules; the Programs contain specific rules regarding the benefits available under the Programs. The Plan and each of the component programs are designed to replace the Company’s prior (and now frozen) deferred compensation plans, namely the Questar Corporation Deferred Compensation Plan (the “Deferred Compensation Plan”), the Questar Corporation Deferred Share Plan (the “Deferred Share Plan”), and the Questar Corporation Deferred Share Make-Up Plan (the “Deferred Share Make-Up Plan”), as of January 1, 2005.

1.2

Status of Plan. This Plan and its component Programs are intended to be an unfunded, nonqualified deferred compensation arrangement for the purpose of providing deferred compensation to “a select group of management or highly-compensated employees” within the meaning of Sections 201(2), 301(a)(3), and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended. The Plan and its component Programs are also intended to comply with Code section 409A and the regulations and guidance promulgated thereunder. Finally, each of the component Programs is intended to qualify as a separate “plan, program, or arrangement” for purposes of 4 U.S.C. 114, thus making payments under the 401(k) Supplemental Program subject to state income tax solely of the state in which the recipient of the payment resides or is domiciled at the time payment is made. Notwithstanding any other provision herein, this Plan and its component Programs shall be interpreted, operated and administered in a manner consistent with these intentions.

1.3

Effect of Plan. The terms of this Plan and each of its component Programs shall govern all amounts deferred on or after January 1, 2005, including any amounts previously deferred or credited under the Deferred Compensation Plan, Deferred Share Plan, or Deferred Share Make-Up Plan (the “Predecessor Plans”) that remain unvested after December 31, 2004.

ARTICLE 2

DEFINITIONS

For purposes of the Plan and each Program established under the Plan, the following terms or phrases shall have the following indicated meanings, unless the context clearly requires otherwise:

2.1

“401(k) Supplemental Program” means the component benefit program of this Plan attached hereto as Appendix B.

2.2

“409A Change in Control” means a Change in Control that is a change in the ownership or effective control of the Company, or in the ownership of a substantial portion of the assets of the Company, as defined in section 409A of the Code and the regulations thereunder, and any successor legislation or guidance that amends, supplements, or replaces same.

2.3

“Account” or “Account Balance” means, for each Participant, the account established for his or her benefit under each Program, which records the credit on the records of the Employer equal to the amounts set aside under the Program and the actual or deemed earnings, if any, credited to such account. The Account Balance, and each other specified account or sub-account, shall be a bookkeeping entry only and shall be used solely as a device for the measurement and determination of the amounts to be paid to a Participant, or his or her designated Beneficiary, pursuant to this Plan and its component Programs.

2.4

“Affiliated Company” means the Company and any entity that is treated as the same employer as the Company under Sections 414(b), (c), (m), or (o) of the Code, any entity required to be aggregated with the Company pursuant to regulations adopted under Code section 409A, or any entity otherwise designated as an Affiliated Company by the Employer.

2.5

“Beneficiary” means that person or persons who become entitled to receive a distribution of benefits under the Plan and its component Programs in the event of the death of a Participant prior to the distribution of all benefits to which he or she is entitled.

2.6

“Change in Control” means the occurrence of any of the following events:

(a)

any Person (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934 (the “Exchange Act’)) other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, is or becomes the beneficial owner (as such term is used in Rule 13d-3 under the Exchange Act) of securities of the Company representing 25 percent or more of the combined voting power of the Company;

(b)

at any time during a period of three (3) consecutive years, individuals who at the beginning of such period constitute the Board (and any new director whose election by the Board or whose nomination for election by the Company’s stockholders was approved by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors at the beginning of such period or whose election or nomination for election was previously so approved) cease to constitute a majority of the Board;

(c)

the merger or consolidation of the Company or any direct or indirect subsidiary of the Company with any other corporation, other than a merger or consolidation that would result in the voting securities of the Company outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof) at least 60 percent of the combined voting power of the securities of the Company or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation, or a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no person is or becomes the beneficial owner, directly or indirectly, of securities of the Company representing 25 percent or more of the combined voting power of the Company’s then outstanding securities; or

(d)

the complete liquidation or dissolution of the Company or the sale or disposition by the Company of all or substantially all of the Company’s assets, other than a sale or disposition by the Company of all or substantially all of the Company’s assets to an entity, at least 60 percent of the combined voting power of the voting securities of which are owned by stockholders of the Company in substantially the same proportions as their ownership of the Company immediately prior to such sale.

2.7

“Code” means the Internal Revenue Code of 1986 and amendments thereto. Reference to a section of the Code shall include that section and any comparable section or sections of any future legislation that amends, supplements or supersedes said section.

2.8

“Committee” means the Management Performance Committee of Questar Corporation.

2.9

“Common Stock” means the no par value common stock of the Company.

2.10

“Company” means Questar Corporation, a corporation organized and existing under the laws of the State of Utah, or its successor or successors.

2.11

“Compensation” means:

(a)

Deferred Compensation Program. With respect to the Deferred Compensation Program an Employee’s salary or wages and payments under incentive compensation plans paid by the Employer and includable in taxable income during the applicable Plan Year, but exclusive of any other forms of additional compensation such as the Employer’s cost for any public or private employee benefit plan, any income recognized by the employee as a result of exercising stock options, moving expenses, the value of restricted stock granted after January 1, 2003, as signing or retention bonuses and any dividends paid on such shares, loan forgiveness, welfare benefits, and severance payments. An Employee’s Compensation for any Plan Year shall include any Elective Deferrals of the Employee under the Company’s Investment Plan or other tax-qualified plans, as well as any Deferral Contributions made to this Plan. An Employee’s Compensation also shall include the amount of any reduction in Compensation for a Plan Year agreed upon under one or more Compensation reduction agreements entered into pursuant to the Questar Corporation Cafeteria Plan and any pre-tax parking payments that are not includable in the gross income of any Employee by reason of Section 132 (f)(4) of the Code.

(b)

401(k) Supplemental Program. For purposes of the 401(k) Supplemental Program, Compensation shall have the same meaning as in paragraph (a), above, except that it shall not include any Deferral Contributions made to the Deferred Compensation Program.

2.12

“Compensation Limit” means the annual limit of Compensation that may be taken into account for purposes of providing benefits under tax-qualified retirement plans, as specified in Section 401(a)(17) of the Code and updated from time to time.

2.13

“Deferral Contributions” means that portion of a Participant’s Compensation that is deferred by a Participant pursuant to the Programs.

2.14

“Deferred Compensation Program” means the component benefit program of this Plan attached hereto as Appendix A.

2.15

“Deferred Compensation Sub-Account” means the sub-account described in Section 5.1 of the Deferred Compensation Program.

2.16

“Disability” means a condition that renders a Participant unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months. A Participant shall not be considered to be disabled unless he furnishes proof of the existence of such disability in such form and manner as may be required by regulations promulgated under, or applicable to, Code Section 409A.

2.17

“Effective Date” means January 1, 2005.

2.18

“Eligible Employee” means any Employee that meets the eligibility requirements of Section 3.1.

2.19

“Employee” means any individual that is among a select group of management or highly compensated employees of an Employer.

2.20

“Employer” means the Company and each Affiliated Company that consents to the adoption of the Plan.

2.21

“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended.

2.22

“Fair Market Value” means the closing benchmark price of the Company’s Common Stock as reported on the composite tape of the New York Stock Exchange for any given valuation date, or if such date is not a trading day, the next preceding trading day.

2.23

“Investment Plan” means the Questar Corporation Employee Investment Plan, as amended from time to time, or any successor plan.

2.24

“Key Employee” means a “specified employee” defined in Code Section 409A(a)(2)(B)(i) and relevant guidance issued thereunder.

2.25

“Key Employee Distribution Date” means the date that is six (6) months after the date of a Key Employee’s Separation from Service.

2.26

“Matching Contributions” means Employer contribution amounts credited to Participants under the Deferred Compensation Program and 401(k) Supplemental Program in addition to (and made on account of) the Participants’ Deferral Contributions under such Programs.

2.27

“Matching Contribution Sub-Account” means the sub-account described in Section 5.1 of the Deferred Compensation Program.

2.28

“Participant” means any individual who has commenced participation in the Plan and its component Programs in accordance with Article 3.

2.29

“Participating Deferral Sub-Account” means the sub-account described in Section 5.1 of the Deferred Compensation Program.

2.30

“Plan” or “Wrap Plan” has the meaning set forth in Section 1.1.

2.31

“Plan Year” means the fiscal year of the Plan, which shall be the calendar year.

2.32

“Predecessor Plans” has the meaning set forth in Section 1.3.

2.33

“Program” means the Deferred Compensation Program and the 401(k) Supplemental Program, or either of them, as the context may require.

2.34

“Separation from Service” means a termination of employment as provided under Code section 409A and the regulations promulgated thereunder, as such may be amended, supplemented or replaced.

ARTICLE 3

ELIGIBILITY; PARTICIPATION

3.1

Eligibility. Eligibility to participate in the Plan shall be determined as follows:

(a)

Any Employee who was an active participant in any of the Predecessor Plans as of December 31, 2004 shall be eligible to participate in this Plan and all of its component Programs as of the Effective Date.

(b)

Any Employee who was not an active participant in any of the Predecessor Plans as of December 31, 2004 shall become eligible to participate in this Plan on the earliest to occur of:

(i)

the date the Employee first becomes an officer of an Employer, in which case the Employee shall be immediately eligible to participate in the 401(k) Supplemental Program and is eligible to participate in the Deferred Compensation Program beginning the first day of the next Plan Year.

(ii)

the date the Employee first receives Compensation in any Plan Year equal to the Compensation Limit, in which case the Employee shall be eligible immediately to participate in the 401(k) Supplemental Program, but shall not be eligible to participate in the Deferred Compensation Program until the first day of the next Plan Year.

(iii)

the date selected by the Committee for the Employee to be eligible to participate in the Plan, in which case the Employee shall be eligible to participate in all of the Plan’s component Programs as of the date selected by the Committee. If such Employee is not an officer of an Employer or has received Compensation in any Plan Year equal to the Compensation Limit, then such Employee must be nominated by his or her Employer as eligible to participate in the Plan and approved by the Committee.

3.2

Enrollment and Commencement of Deferrals. Except as provided below with regard to automatic enrollment in the 401(k) Supplemental Program, each new Eligible Employee who wishes to make Deferral Contributions must timely complete, execute, and return to the Committee such election forms or other enrollment materials as the Committee requires. Such enrollment requirements must be completed:

(a) in the case of an Eligible Employee who first becomes eligible to participate as of the first day of a Plan Year, on or prior to December 31^st of the prior Plan Year or such other earlier date as the Committee establishes in its sole and absolute discretion.

(b) in the case of an Eligible Employee who first becomes eligible to participate after the first day of a Plan Year, within thirty (30) days after the date the Eligible Employee first becomes eligible to participate, or such other earlier date as the Committee establishes in its sole and absolute discretion.

If an Eligible Employee fails to timely complete the election forms or other enrollment materials, the Eligible Employee shall be automatically enrolled in the 401(k) Supplemental Program in accordance with the deemed deferral elections set forth in Section 4, but shall not be enrolled in the Deferred Compensation Program until the first day of the first Plan Year beginning after the date he or she completes and returns the enrollment materials to the Committee.

3.3

Failure of Eligibility. If the Committee determines, in its sole and absolute discretion, that any Participant no longer qualifies as a member of a select group of management or highly compensated employees of the Employer, the Participant shall cease active participation in this Plan and all contributions to the Plan by or on behalf of the Participant shall cease. The Committee’s determination shall be final and binding on all persons.

ARTICLE 4

ELECTIONS

4.1

Elections, General

(a)

First Year of Plan Participation. In connection with a Participant’s enrollment in the Plan pursuant to Section 3.2, the Participant shall make an irrevocable election to defer (or not to defer) Compensation in accordance with the terms of the component Programs for which he is eligible, which election shall apply to the year in which the Participant commences participation. Such election shall apply solely to Compensation to be paid with respect to services performed on or after his or her enrollment, except to the extent permissible under Code Section 409A and guidance thereunder. The Participant’s deferral election shall continue to apply for all succeeding Plan Years unless and until revoked or modified pursuant to Section 4.1(b), below. If the Participant fails to complete and return timely the enrollment materials in accordance with Section 3.2, then the Participant shall be deemed to have elected to make the Deferral Contributions permitted under the 401(k) Supplemental Program.

In connection with a Participant’s enrollment in the Plan pursuant to Section 3.2, the Participant shall also make the following elections with respect to each Program under the Plan:

(i)

Deferred Compensation Program. If eligible to participate in the Deferred Compensation Program for the year in which the Participant commences participation under the Plan, the Participant shall make an irrevocable election (from the options available under Section 6, below) as to the time and form of payment of any Deferral or Matching Contributions credited to his or her Account Balance under the Deferred Compensation Program for such year (including earnings thereon). If the Participant fails to make an election as to the time and form of payment, or if the Participant’s election does not meet the requirements of Code Section 409A and related Treasury guidance or regulations, the Participant shall be deemed to have elected to receive a lump sum distribution as soon as legally and administratively practicable following the earliest to occur of the Participant’s (A) Separation from Service, (B) Disability, or (C) death. The Participant’s election (or deemed election) shall continue to apply for succeeding years unless and until the election is modified pursuant to Section 4.1(b), below. Any such modification shall apply prospectively only and shall not apply to Deferral or Matching Contributions previously credited under the Program (or any earning thereon).

(ii)

401(k) Supplemental Program. The Participant shall make an irrevocable election as to the time and form of payment of all amounts credited to his or her Account Balance under the 401(k) Supplemental Program from the options available under Section 6, below. Such election shall be irrevocable and shall apply to the Participant’s entire Account Balance under the Program, including all amounts deferred in subsequent Plan Years and any related earnings. If the Participant fails to make an election as to the time and form of payment, or if the Participant’s election does not meet the requirements of Code Section 409A and related Treasury guidance or regulations, the Participant shall be deemed to have elected to receive a lump sum distribution as soon as legally and administratively practicable following the earliest to occur of the Participant’s (A) Separation From Service, (B) Disability, or (C) death.

(b)

Subsequent Plan Years. For each succeeding Plan Year, the Participant may, prior to December 31^st of the immediately preceding Plan Year (or such earlier deadline as is established by the Committee in its sole discretion):

(i)

make an initial deferral election under the Deferred Compensation Program or modify or revoke his or her existing deferral elections under either or both of the Programs. All such elections shall be made in accordance with the terms of the Programs and shall remain in effect for subsequent Plan Years unless timely revoked or modified by the Participant in accordance with this Section.

(ii)

make an initial election under the Deferred Compensation Program or modify his or her existing election under the Deferred Compensation Program as to the time and form of payment of any future Deferral or Matching Contributions credited to his or her Account Balance under such Program (and related earnings). Such election shall be made in accordance with the terms of the Deferred Compensation Program and Section 6, below, and shall remain in effect for subsequent Plan Years unless and until timely modified by the Participant in accordance with this Section. Any such modification shall apply prospectively only and shall not apply to Deferral or Matching Contributions previously credited under the Program (or any earning thereon).

Any election(s) made in accordance with this Section shall be irrevocable; provided, however, that if the Committee requires Participants to make a deferral election for “performance-based compensation” or “compensation subject to a substantial risk of forfeiture” by the deadline(s) described above, it may, in its sole discretion, and in accordance with Code Section 409A and related Treasury guidance or regulations, permit a Participant to subsequently change his or her elections for such Compensation no later than the deadlines established by the Committee pursuant to Section 4.1(c) or 4.1(d), below.

(c)

Performance-Based Compensation. The Committee may, in its sole discretion, determine that an irrevocable deferral election pertaining to “performance-based compensation” based on services performed over a period of at least twelve (12) months, may be made no later than six (6) months before the end of the performance service period. “Performance-based compensation” shall be Compensation, the payment or amount of which is contingent on pre-established organizational or individual performance criteria, which satisfies the requirements of Code Section 409A and related Treasury guidance or regulations. In order to be eligible to make a deferral election for performance-based compensation, a Participant must perform services continuously from a date no later than the date upon which the performance criteria for such Compensation are established through the date upon which the Participant makes a deferral election for such Compensation. In no event shall an election to defer performance-based compensation be permitted after such Compensation has become both substantially certain to be paid and readily ascertainable.

(d)

Compensation Subject to Risk of Forfeiture. With respect to compensation (i) to which a Participant has a legally binding right to payment in a subsequent year, and (ii) that is subject to a forfeiture condition requiring the Participant’s continued services for a period of at least twelve (12) months from the date the Participant obtains the legally binding right, the Committee may, in its sole discretion, determine that an irrevocable deferral election for such compensation may be made no later than the 30^th day after the Participant obtains the legally binding right to the compensation, provided that the election is made at least twelve (12) months in advance of the earliest date at which the forfeiture condition could lapse.

4.2

409A Transition Elections. Notwithstanding the required deadline for the submission of an election as to the time and form of payment (as set forth in Section 4.1), the Committee may, as permitted by Code Section 409A and related Treasury guidance or regulations, provide a limited period in which Participants may make new distribution elections, which limited period shall in all events expire on December 31, 2007. Any election as to the time and form of payment made in accordance with the requirements established by the Committee, pursuant to this section, shall not be treated as a change in the form or timing of a Participant’s benefit payment for purposes of Code Section 409A or the Plan.

The Committee shall interpret all provisions relating to an election submitted in accordance with this section in a manner that is consistent with Code Section 409A and related Treasury guidance or regulations. If any distribution election submitted prior to December 31, 2006 in accordance with this section either (i) relates to payments that a Participant would otherwise receive in 2006, or (ii) would cause payments to be made in 2006, such election shall not be effective. If any distribution election submitted on or after January 1, 2007 and prior to December 31, 2007 in accordance with this section either (i) relates to payments that a Participant would otherwise receive in 2007, or (ii) would cause payments to be made in 2007, such election shall not be effective.

4.3

Election Forms. All elections shall be made on forms prepared by the Committee and must be dated, signed, and filed with the Company’s Vice President of Human Resources in order to be valid.

ARTICLE 5

ACCOUNT STATEMENTS

At least once a year within 60 days after the end of each Plan Year, a statement shall be sent to each Participant listing his or her Account Balance for each Program as of the last day of the Plan Year. The statement shall also include the Deferral Contributions made by the Participant to each Program for the Plan Year, along with any Matching Contributions credited to the Participant’s Account Balances and the investment gains or losses (including reinvested dividends) credited during the Plan Year. Such information shall be reflected on a payroll by payroll basis.

ARTICLE 6

DISTRIBUTIONS

6.1

Permissible Times and Forms of Payments. A Participant may elect to receive his or her Account under the Deferred Compensation Program (or relevant portion thereof), or his or her Account under the 401(k) Supplemental Program at the following times and in the following forms, provided, however, that the Participant’s Account must be distributed in full within five years of the Distribution Event set forth below:

(a)

Time of Distribution. The Participant may elect to receive a distribution on (or as soon thereafter as administratively feasible), or at a designated anniversary date following, the first to occur of a Participant’s Disability, Separation from Service, or death (“Distribution Event”).

(b)

Form of Distribution. A Participant may elect to receive a distribution of his or her Account (or any relevant portion of his or her Account under the Deferred Compensation Program) in any of the following forms:

(i)

a single lump sum.

(ii)

up to four (4) annual installments.

6.2

Change in Control.

(a)

409A Change in Control. Notwithstanding any election made by the Participant, in the event of a 409A Change in Control, all amounts then credited to the Participant’s Account shall be distributed to him in a single lump sum within 60 days following the 409A Change in Control.

(b)

Other Change in Control. To the extent permissible by Code Section 409A and the guidance issued thereunder, in the event of a Change in Control that does not also qualify as a 409A Change in Control, all amounts then credited to the Participant’s Account shall, subject to Section 6.4, be distributed to the Participant within 30 days of Participant’s Separation from Service, death, or Disability, provided such Separation from Service, death, or Disability occurs within three (3) years following the Change in Control. If such event does not occur within three (3) years following the Change in Control, or if the Committee determines that the foregoing provision violates Code Section 409A and the guidance issued thereunder, the Participant’s Account shall be distributed in accordance with the Participant’s elections under Section 4.

6.3

Calculation of Distributions.

(a)

Lump Sum. All lump sum distributions shall be based on the value of the Participant’s Account (or the portion thereof being distributed) as of the last day of the calendar month preceding the payment date.

(b)

Installment Distributions. Under an installment payout, the Participant’s first installment shall be equal to a fraction of the balance credited to his or her Account (or the portion of his or her account to be paid in installments) as of the last day of the calendar month preceding such payment, the numerator of which is one and the denominator of which is the total number of installments selected. The amount of each subsequent payment shall be a fraction of the balance in the Participant’s Account (or the portion of his or her account to be paid in installments) as of the last day of the calendar month preceding each subsequent payment, the numerator of which is one and the denominator of which is the total number of installments elected minus the number of installments previously paid.

6.4

Key Employees. In the event a Participant is a Key Employee, distribution on account of the Key Employee’s Separation from Service cannot commence before the Key Employee Distribution Date. In such event, any and all payments that would otherwise be made to the Participant prior to the Key Employee Distribution Date shall be delayed until the Key Employee Distribution Date and paid on such date or as soon thereafter as is administratively feasible. This paragraph shall not apply to any payments that would otherwise be (and are) made on or after the Key Employee Distribution Date.

6.5

Method of Payment. All payments shall be made in cash.

ARTICLE 7
ADMINISTRATION

7.1

Committee to Administer and Interpret Plan and Component Programs. The Committee shall administer the Plan and its component Programs and shall have all discretion and power necessary for that purpose. The Committee shall have the discretion, authority, and power to (i) make, amend, interpret, and enforce all appropriate rules and regulations for the administration of the Plan and its component Programs and (ii) decide or resolve any and all questions as may arise in connection with this Plan and its component Programs, including interpretations of the Plan and its component Programs and determinations of eligibility to participate and to receive distributions under the Plan and its component Programs. Any individual serving on the Committee shall not vote or act on any matter relating solely to himself. When making a determination or calculation, the Committee shall be entitled to rely on information supplied by a Participant, Beneficiary, or the Employer, as the case may be. The Committee shall maintain all records of the Plan and its component Programs.

7.2

Agents. In the administration of this Plan and its component Programs, the Committee may, from time to time, employ agents (including officers and other employees of the Company) and delegate to them such administrative duties as it sees fit (including acting through a duly appointed representative) and may from time to time consult with counsel who may be counsel to the Company.

7.3

Binding Effect of Decisions. The decision or action of the Committee with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and its component Programs and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan and its component Programs.

7.4

Indemnity of Committee. The Company shall indemnify and hold harmless the members of the Committee and any employee to whom duties of the Committee may be delegated against any and all claims, losses, damages, expenses or liabilities arising from any action or failure to act with respect to this Plan and its component Programs, except in the case of willful misconduct by the Committee, any of its members, or any such employee.

7.5

Employer Information. To enable the Committee to perform its functions, the Employer shall supply full and timely information to the Committee on all matters relating to the compensation of its Participants, the date and circumstances of the Disability (as defined above), death or Separation from Service of a Participant, and such other pertinent information as the Committee may reasonably require.

7.6

Agent for Legal Process. The Committee shall be agent of the Plan and its component Programs for service of all legal process.

ARTICLE 8

CLAIMS PROCEDURE

8.1

Filing a Claim. All claims under this Plan and its component Programs shall be filed in writing by the Participant, his or her Beneficiary, or the authorized representative of either, by completing the procedures that the Committee requires. The procedures shall be reasonable and may include the completion of forms and the submission of documents and additional information. All claims shall be filed in writing with the Committee according to the Committee’s procedures no later than one year after the occurrence of the event that gives rise to the claim. If the claim is not filed within the time described in the preceding sentence, the claim shall be barred.

8.2

Review of Initial Claim.

(a)

Initial Period for Review of the Claim. The Committee shall review all materials and shall decide whether to approve or deny the claim. If a claim is denied in whole or in part, written notice of denial shall be furnished by the Committee to the claimant within a reasonable time after the claim is filed but not later than ninety (90) days after the Committee receives the claim. The notice shall set forth the specific reason(s) for the denial, reference to the specific Plan or Program provisions on which the denial is based, a description of any additional material or information necessary for the claimant to perfect his or her claim and an explanation of why such material or information is necessary, and a description of the Plan’s review procedures, including the applicable time limits and a statement of the claimant’s right to bring a civil action under ERISA section 502(a) following a denial of the appeal.

(b)

Extension. If the Committee determines that special circumstances require an extension of time for processing the claim, it shall give written notice to the claimant and the extension shall not exceed ninety (90) days. The notice shall be given before the expiration of the ninety (90) day period described in Section 8.2(a) above and shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render its decision.

8.3

Appeal of Denial of Initial Claim. The claimant may request a review upon written application, may review pertinent documents, and may submit issues or comments in writing. The claimant must request a review within a reasonable period of time prescribed by the Committee. In no event shall such a period of time be less than sixty (60) days.

8.4

Review of Appeal.

(a)

Initial Period for Review of the Appeal. The Committee shall conduct all reviews of denied claims and shall render its decision within a reasonable time, but not to exceed than sixty (60) days of the receipt of the appeal by the Committee. The claimant shall be notified of the Committee’s decision in a notice, which shall set forth the specific reason(s) for the denial, reference to the specific Plan or Program provisions on which the denial is based, a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to and copies of all documents, records, and other information relevant to the claimant’s claim, and a statement of the claimant’s right to bring a civil action under ERISA section 502(a) following a denial of the appeal.

(b)

Extension. If the Committee determines that special circumstances require an extension of time for reviewing the appeal, it shall give written notice to the claimant and the extension shall not exceed sixty (60) days. The notice shall be given before the expiration of the sixty (60) day period described in Section 8.4(a) above and shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render its decision.

8.5

Form of Notice to Claimant. The notice to the claimant shall be given in writing or electronically and shall be written in a manner calculated to be understood by the claimant. If the notice is given electronically, it shall comply with the requirements of Department of Labor Regulation § 2520.104b-1(c)(1)(i), (iii), and (iv).

8.6

Discretionary Authority of Committee. The Committee shall have full discretionary authority to determine eligibility, status, and the rights of all individuals under the Plan and its component Programs, to construe any and all terms of the Plan and its component Programs, and to find and construe all facts.

ARTICLE 9

AMENDMENT AND TERMINATION OF PLAN

The Board may at any time amend, modify, or terminate this Plan and its component Programs; provided, however, that no such amendment may reduce any Participant’s Account Balances under the Plan or any component Program as it existed prior to the date of such amendment or termination. Notwithstanding the foregoing, the Company may, in its sole discretion, amend the Plan and its component Programs without the consent of a Participant or his or her Beneficiary (even if such amendment is adverse to their interests and/or benefit under the Plan or its component Programs) to the minimum extent necessary to meet the requirements of Code Section 409A.

ARTICLE 10

MISCELLANEOUS

10.1

Source of Payments. Each participating Employer will pay all benefits for its Employees arising under this Plan and its component Programs, and all costs, charges and expenses relating to such benefits, out of its general assets.

10.2

No Assignment or Alienation.

(a)

General. Except as provided in subsection (b) below, the benefits provided for in this Plan and its component Programs shall not be anticipated, assigned (either at law or in equity), alienated, or be subject to attachment, garnishment, levy, execution or other legal or equitable process. Any attempt by any Participant or any Beneficiary to anticipate, assign or alienate any portion of the benefits provided for in this Plan or its component Programs shall be null and void.

(b)

Exception: QDRO. The restrictions of subsection (a) shall not apply to a distribution to an “alternate payee” (as defined in Code section 414(p)) pursuant to a “qualified domestic relations order” (“QDRO”) within the meaning of Code section 414(p)(11). The Committee shall have the discretion, power, and authority to determine whether a domestic relations order is a QDRO. Upon a determination that an order is a QDRO, the Committee shall direct the Employer to distribute to the alternate payee or payees named in the QDRO as directed by the QDRO.

10.3

Beneficiaries. A Participant shall have the right, in accordance with forms and procedures established by the Committee, to designate one or more beneficiaries to receive some or all amounts payable under each of the component Programs after the Participant’s death. The Participant need not designate the same Beneficiary for each Program under the Plan. In the absence of an effective beneficiary designation for a Program, all payments of a Participant’s Account under the 401(k) Supplemental Program and the Participating Deferral Sub-Account and Matching Contribution Sub-Account under the Deferred Compensation Program shall be made to the beneficiary named by the Participant under the terms of the Investment Plan and any payment of a Participant’s Deferred Compensation Sub-Account under the Deferred Compensation Program shall be made to the personal representative of the Participant’s estate.

10.4

No Creation of Rights. Nothing in this Plan or its component Programs shall confer upon any Participant the right to continue as an Employee of an Employer. The right of a Participant to receive a cash distribution shall be an unsecured claim against the general assets of his or her Employer. Nothing contained in this Plan or its component Programs nor any action taken hereunder shall create, or be construed to create, a trust of any kind, or a fiduciary relationship between the Company and the Participants, Beneficiaries, or any other persons. All Accounts under the Plan and its component Programs shall be maintained for bookkeeping purposes only and shall not represent a claim against specific assets of any Employer.

10.5

Furnishing Information. A Participant or his or her Beneficiary shall cooperate with the Committee by furnishing any and all information requested by the Committee and take such other actions as may be requested in order to facilitate the administration of the Plan and its component Programs and the payment of benefits thereunder.

10.6

Payments to Incompetents. If the Committee determines in its discretion that a benefit under this Plan or any of its component Programs is to be paid to a minor, a person declared incompetent or to a person incapable of handling the disposition of his or her property, the Committee may direct payment of such benefit to the guardian, legal representative or person having the care and custody of such minor, incompetent or incapable person. The Committee may require proof of minority, incompetence, incapacity or guardianship, as it may deem appropriate prior to distribution of the benefit. Any payment of a benefit shall be a payment for the account of the Participant and the Participant’s Beneficiary, as the case may be, and shall be a complete discharge of any liability under the Plan and its component Programs for such payment amount.

10.7

Court Order. The Committee is authorized to make any payments directed by court order in any action in which the Plan or the Committee has been named as a party.

10.8

Code Section 409A Savings Clause. It is the intent of the Company that all payments and benefits under this Plan be made in accordance with Code Section 409A or an exception thereto. To the extent that any payment or benefit would violate Code Section 409A the Committee shall delay or restructure such payment or benefit to the minimum extent necessary to avoid the application of Code Section 409A.

10.9

Attorney Fees; Interest. The Company agrees to pay as incurred, to the full extent permitted by law, and in accordance with Section 409A, all legal fees and expenses which a Participant may reasonably incur as a result of any contest (regardless of the outcome thereof) by the Company, the Participant, or others following a Change in Control regarding the validity or enforceability of, or liability under, any provision of this Plan or any guarantee of performance thereof (including as a result of any contest by the Participant about the amount of any payment pursuant to this Plan), plus in each case interest on any delayed payment at the applicable Federal rate provided for in Section 7872(f)(2)(A) of the Code. The foregoing right to legal fees and expenses shall not apply to any contest brought by a Participant (or other party seeking payment under the Plan) that is found by a court of competent jurisdiction to be frivolous or vexatious.

10.10

Distribution in the Event of Taxation. If, for any reason, all or any portion of a Participant’s benefits under this Plan or any of its component Programs becomes subject to federal income tax with respect to the Participant prior to receipt, a Participant may petition the Committee for a distribution of that portion of his or her benefit that has become taxable. Upon the grant of such a petition, which grant shall not be unreasonably withheld, the Employer shall distribute to the Participant immediately available funds in an amount equal to the taxable portion of his or her benefit (which amount shall not exceed a Participant’s unpaid Account Balances). If the petition is granted, the tax liability distribution shall be made within 90 days of the date when the Participant’s petition is granted. Such a distribution shall affect and reduce the benefits to be paid under this Plan and its component Programs.

10.10

Governing Law. To the extent not preempted by federal law, this Plan and its component Programs shall be governed by the laws of the State of Utah, without regard to conflicts of law principles.

Exhibit A

DEFERRED COMPENSATION PROGRAM

a component Program of the

Questar Corporation Deferred Compensation Wrap Plan

QUESTAR CORPORATION

DEFERRED COMPENSATION PROGRAM

ARTICLE 1

INTRODUCTION

1.1

Establishment of Program. The Company hereby establishes this Deferred Compensation Program under the Wrap Plan, effective as of January 1, 2005. The Deferred Compensation Program is designed to replace both the Company’s frozen Deferred Compensation Plan and Deferred Share Plan, and any amounts previously credited under the Deferred Share Plan that remain unvested after December 31, 2004 shall be accounted for under the terms of this Program.

1.2

Purpose. The purposes of this Program are (i) to provide eligible Employees with the opportunity to defer receipt of up to a specified portion of their annual Compensation in order to reduce current taxable income and to provide for future retirement needs, and (ii) to provide a benefit to each Participant approximately equal to the benefit he would have received under the Investment Plan if the Participant did not elect to defer Compensation under this Program but instead contributed an applicable portion of such amount to the Investment Plan.

ARTICLE 2

PARTICIPATION; ELECTIONS

2.1

Participation. Each Eligible Employee shall participate in the Deferred Compensation Program at the time set forth in Article 3 of the Wrap Plan.

2.2

Elections. Each Participant shall make elections with regard to the deferral of Compensation and the time and form of payments under the Program in accordance with Article 4 of the Wrap Plan.

ARTICLE 3

DEFERRAL CONTRIBUTIONS

Each Plan Year, a Participant, if choosing to defer Compensation under the Program for such Plan Year, must defer a minimum of $5,000 and may defer up to a maximum of 50% of his or her Plan Year Compensation.

ARTICLE 4

MATCHING CONTRIBUTIONS

4.1

Amount of Matching Contributions. A Participant who makes Deferral Contributions to this Program for a Plan Year shall be entitled to a Matching Contribution for such Plan Year in an amount determined on the same basis as matching contributions are determined for the Investment Plan.

4.2

Vesting. A Participant shall be vested in the portion of his or her Account attributable to Matching Contributions to the same extent as such Participant is vested in any matching contributions under the Investment Plan.

ARTICLE 5

ACCOUNTS; DEEMED INVESTMENTS

5.1

Accounts. The Committee shall establish an Account for each Participant with at least three sub-accounts as follows:

(a)

a Deferred Compensation Sub-Account which shall reflect all annual Deferral Contributions made by the Participant, minus amounts placed in the Participating Deferral Sub-Account, together with any adjustments for income, gain or loss and any payments from such sub-account as provided herein;

(b)

a Participating Deferral Sub-Account which shall reflect the portion of the annual Deferral Contributions made by the Participant for which the Participant receives a Matching Contribution under this Program, together with any adjustments for income, gain or loss and any payments from such sub-account as provided herein; and

(c)

a Matching Contribution Sub-Account which shall reflect all Company Matching Contributions made under the Program, together with any adjustments for income, gain or loss and any payments from such sub-account as provided herein.

The Committee shall establish such other sub-accounts as it deems necessary or desirable for the proper administration of this Program. Amounts deferred by a Participant under this Program shall be credited to the Participant’s Account and relevant sub-account as soon as administratively practicable after the amounts would have otherwise been paid to the Participant.

5.2

Status of Accounts. Accounts and sub-accounts established hereunder shall be record-keeping devices utilized for the sole purpose of determining benefits payable under this Program, and will not constitute a separate fund of assets but shall continue for all purposes to be part of the general, unrestricted assets of the Employer, subject to the claims of its general creditors.

5.3

Deemed Investment of Amounts Deferred.

(a)

Participating Deferral and Matching Contribution Sub-Account. The Participant’s Participating Deferral and Matching Contribution Sub-Account shall be deemed invested in shares of Common Stock purchased at Fair Market Value on the date(s) on which the Deferral Contributions or Matching Contributions are credited to the Participant’s Account. In addition, the Participant’s Participating Deferral and Matching Contribution Sub-Account shall be credited on a quarterly basis with an amount equal to the dividends that would have become payable during the deferral period if actual purchases of Common Stock had been made, with such dividends accounted for as if invested in Common Stock as of the payable date for such dividends. Any credited shares treated as if they were purchased with dividends shall be deemed to have been purchased at Fair Market Value on the dividend payment date.

(b)

Deferred Compensation Sub-Account. In connection with his or her enrollment in the Program, a Participant may elect to have earnings, gains, or losses with respect to his or her Deferred Compensation Sub-Account calculated based on the deemed investment alternatives below, in increments of 25%, 50%, 75%, or 100%. In the event the Participant fails to make an election regarding the deemed investment of his or her Deferred Compensation Sub-Account, the Participant shall be deemed to have elected to invest 100% of his or her Deferred Compensation Sub-Account in the Common Stock Option (as described below). The Participant’s investment election shall continue in effect unless and until modified by the Participant. Any such modification shall apply prospectively only and shall not apply to amounts previously deferred under this Program (and related earnings). Any such modification must be made effective as of the first day of a Plan Year, and must be made prior to the first day of such Plan Year.

(a)

Common Stock Option. Any portion of the Deferred Compensation Sub-Account deemed invested under this option (the “Common Stock Option”) shall be accounted for as if invested in shares of Common Stock purchased at Fair Market Value on the date on which a Deferral Contribution is credited to the Participant’s Account. The Participant’s Deferred Compensation Sub-Account shall be credited on a quarterly basis with an amount equal to the dividends that would have become payable during the deferral period if actual purchases of Common Stock had been made, with such dividends accounted for as if invested in Common Stock as of the payable date for such dividends. Any credited shares treated as if they were purchased with dividends shall be deemed to have been purchased at Fair Market Value on the dividend payment date.

(b)

Treasury Note Option. Any portion of the Deferred Compensation Sub-Account deemed invested under this option (the “Treasury Note Option”) shall be credited with interest at a monthly rate calculated by dividing by 12 the sum of 100 basis points plus the rate for the appropriate 10-Year Treasury Note as quoted in the Wall Street Journal under “Consumer Savings Rates” on the Thursday closest to the end of the month or other published source of such rates as identified by Questar Corporation’s Treasury department. The appropriate 10-Year Treasury Note shall be the Note that is the closest (in terms of months) to the date on which the interest is credited. The interest deemed to be credited to each Deferred Compensation Sub-Account shall be based on the amount credited to such Account at the beginning of each particular month.

ARTICLE 6

DISTRIBUTIONS

All distributions of a Participant’s Account under this Program shall be made in accordance with the Participant’s election(s) (or deemed election(s)) under Article 4 of the Wrap Plan.

Exhibit B

401(k) SUPPLEMENTAL PROGRAM

a component Program of the

Questar Corporation Deferred Compensation Wrap Plan

QUESTAR CORPORATION

401(k) SUPPLEMENTAL PROGRAM

ARTICLE 1

INTRODUCTION

1.1

Establishment of Program. The Company hereby establishes this 401(k) Supplemental Program under the Wrap Plan, effective as of January 1, 2005. The 401(k) Supplemental Program is designed to replace the Company’s frozen Deferred Share Make-Up Plan, and any amounts previously deferred or credited under the Deferred Share Make-Up Plan that remain unvested after December 31, 2004 shall be accounted for under the terms of this Program.

1.2

Purpose. The purpose of this supplemental Program is to provide a benefit to an Employee approximately equal to the benefit he would have received under the Investment Plan if the Compensation Limit were inapplicable.

ARTICLE 2

PARTICIPATION; ELECTIONS

2.1

Participation. Each Eligible Employee shall participate in the 401(k) Supplemental Program at the time set forth in Article 3 of the Wrap Plan.

2.2

Elections. Each Participant shall make elections with regard to the deferral of Compensation and the time and form of payments under this Program in accordance with Article 4 of the Wrap Plan.

ARTICLE 3

DEFERRAL CONTRIBUTIONS

Each Plan Year, a Participant choosing to defer Compensation under this Program must defer 6% of his or her Plan Year Compensation in excess of the Compensation Limit.

ARTICLE 4

MATCHING CONTRIBUTIONS

4.1

4.2

ARTICLE 5

ACCOUNTS; DEEMED INVESTMENTS

5.1

Accounts. The Committee shall establish an Account and sub-accounts for each Participant as are necessary for the proper administration of this 401(k) Supplemental Program. Such Accounts shall reflect Deferrals Contributions and Matching Contributions made by or on behalf of the Participant, together with any adjustments for income, gain or loss and any payments from the Account as provided herein. Deferral Contributions and related Matching Contributions shall be credited to the Participant’s Account as soon as administratively practicable after the Deferral Contribution would have otherwise been paid to the Participant.

5.2

5.3

Deemed Investment in Company Stock. The Participant’s Account shall be deemed invested in shares of Common Stock purchased at Fair Market Value on the date(s) on which the Deferral Contributions or Matching Contributions are credited to the Participant’s Account. In addition, the Participant’s Account shall be credited on a quarterly basis with an amount equal to the dividends that would have become payable during the deferral period if actual purchases of Common Stock had been made, with such dividends accounted for as if invested in Common Stock as of the payable date for such dividends. Any credited shares treated as if they were purchased with dividends shall be deemed to have been purchased at Fair Market Value on the dividend payment date.

ARTICLE 6

DISTRIBUTIONS

All distributions of a Participant’s Account under this Program shall be made in accordance with the Participant’s election(s) (or deemed election(s)) under Article 4 of the Wrap Plan.

Exhibit 31.1.

CERTIFICATION

I, Keith O. Rattie, certify that:

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

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

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

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

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

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

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

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

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

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

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

November 3, 2006

/s/Keith O. Rattie

Keith O. Rattie

Chairman, President and Chief

Executive Officer

Exhibit 31.2.

CERTIFICATION

I, S. E. Parks, certify that:

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

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

November 3, 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 September 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

November 3, 2006

/s/Keith O. Rattie

Keith O. Rattie

Chairman, President and Chief Executive Officer

November 3, 2006

/s/S. E. Parks

S. E. Parks

Senior Vice President and Chief Financial Officer