SEC Filing | QEP Resources, Inc.

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UNITED STATES

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]

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

For the quarter ended June 30, 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 0-30321

QUESTAR MARKET RESOURCES, INC.
(Exact name of registrant as specified in charter)

STATE OF UTAH 87-0287750

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

incorporation or organization) Identification No.)

180 East 100 South Street, P.O. Box 45601 Salt Lake City, Utah 84145-0601
(Address of principal executive offices)

Registrant’s telephone number, including area code (801) 324-2600

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

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

On July 31, 2006, 4,309,427 shares of the registrant’s common stock, $1.00 par value, were outstanding (all shares are owned by Questar Corporation).

Registrant meets the conditions set forth in General Instruction H (1) (a) and (b) of Form 10-Q and is filing this Form 10-Q with the reduced disclosure format.

Questar Market Resources, Inc.

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

TABLE OF CONTENTS

Nature of Business

Where You Can Find More Information

Forward-Looking Statements

Glossary of Commonly Used Terms

PART I.

FINANCIAL INFORMATION

Item 1.

Financial Statements (Unaudited)

Consolidated Statements of Income for the three and six months ended

June 30, 2006 and 2005

Condensed Consolidated Balance Sheets as of June 30, 2006

and December 31, 2005

Condensed Consolidated Statements of Cash Flows for the six months ended

June 30, 2006 and 2005

Notes Accompanying the Consolidated Financial Statements

Item 2.

Management’s Discussion and Analysis of Financial Condition and

Results of Operations

Item 3.

Quantitative and Qualitative Disclosures About Market Risk.

Item 4.

Controls and Procedures

PART II.

OTHER INFORMATION

Nature of Business

Questar Market Resources, Inc. (Market Resources or the Company) is a natural gas-focused energy company, a wholly-owned subsidiary of Questar Corporation (Questar) and Questar’s primary growth driver. Market Resources is a sub-holding company with four principal subsidiaries:

Questar Exploration and Production Company (Questar E&P) acquires, explores for, 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; and

Questar Energy Trading Company (Energy Trading) markets equity and third-party gas and oil, provides risk-management services, and owns and operates an underground gas-storage reservoir.

Market Resources operates in the Rocky Mountain and Midcontinent regions of the United States of America and is headquartered in Salt Lake City, Utah.

Where You Can Find More Information

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

Interested parties can also access financial and other information via Questar’s website at www.questar.com. Questar and Market Resources make available, free of charge, through the website copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to such reports. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC. Questar’s website also contains Statements of Responsibility for Board Committees, Corporate Governance Guidelines and the Business Ethics and Compliance Policy.

Finally, you may request a copy of filings, other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing or calling Market Resources, 180 East 100 South Street, P.O. Box 45601, Salt Lake City, Utah 84145-0601 (telephone number (801) 324-2600).

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 antic ipated 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.

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

Glossary of Commonly Used Terms

Billion.

bbl

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

basis

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

Btu

One British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.

cash flow hedge

A derivative instrument that complies with Statement of Financial Accounting Standards (SFAS) 133, as amended, and is used to reduce the exposure to variability in cash flows from the forecasted physical sale of gas and oil production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted physical sale.

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

cfe

Cubic feet of natural gas equivalents.

development well

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

dewpoint

A specific temperature and pressure at which hydrocarbons condense to form a liquid.

dry hole

A well drilled and found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of production exceed expenses and taxes.

dth

Decatherms or ten therms. One dth equals one million Btu or approximately one Mcf.

dthe

Decatherms of natural gas equivalents.

equity production

Production at the wellhead attributed to Company ownership.

exploratory well

A well drilled into a previously untested geologic prospect to determine the presence of gas or oil.

finding costs

Finding costs are the sum of costs incurred for gas and oil exploration and development activities; including purchases of reserves in place, leasehold acquisitions, seismic, geological and geophysical, development and exploration drilling and asset retirement obligations for a given period, divided by the total amount of estimated net proved reserves added through discoveries, positive and negative revisions and purchases in place for the same period. The Company expresses finding costs in dollars per Mcfe averaged over a five-year period.

frac spread

The difference between the market value for NGL extracted from the gas stream and the market value of the Btu-equivalent volume of natural gas required to replace the extracted liquids.

futures contract

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

gal

U.S. gallon.

gas

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

gross

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

hedging

The use of derivative commodity and interest-rate instruments to reduce financial exposure to commodity price and interest-rate volatility.

infill development drilling

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

lease operating expenses

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

Thousand.

Million.

natural gas equivalents

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

natural gas liquids (NGL)

Liquid hydrocarbons that are extracted and separated from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and heavier hydrocarbons.

net

“Net” gas and oil wells or “net” acres are determined by the sum of the fractional ownership working interest the Company has in those gross wells or acres.

net revenue interest

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

production replacement ratio

The production replacement ratio is calculated by dividing the net proved reserves added through discoveries, positive and negative revisions and purchases and sales in-place for a given period by the production for the same period, expressed as a percentage. The production replacement ratio is typically reported on an annual basis.

proved reserves

Those quantities of natural gas, crude oil, condensate and NGL on a net revenue interest basis, which geological and engineering data demonstrate with reasonable certainty to be recoverable under existing economic and operating conditions. See 17 C.F.R. Section 4-10(a)(2) for a complete definition.

proved developed reserves

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

proved developed producing reserves

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

proved undeveloped reserves

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

reservoir

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

royalty

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

seismic

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

wet gas

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

working interest

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

workover

Operations on a producing well to restore or increase production.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
	(in thousands, except per share amounts)

REVENUES
From unaffiliated customers	$384,110	$ 344,896	$799,187	$ 659,234
From affiliates	40,164	35,741	92,601	73,825
TOTAL REVENUES	424,274	380,637	891,788	733,059

OPERATING EXPENSES
Cost of natural gas and other products sold	140,274	168,696	303,423	315,229
Operating and maintenance	42,203	36,991	87,590	68,650
General and administrative	15,486	13,335	32,059	27,705
Production and other taxes	20,129	20,962	48,054	42,206
Depreciation, depletion and amortization	54,613	41,257	107,635	81,116
Exploration	10,101	5,476	13,400	6,849
Abandonment and impairment of gas,
oil and other properties	1,843	1,493	3,542	2,898
Wexpro Agreement – oil-income sharing	1,237	1,364	2,814	2,625

TOTAL OPERATING EXPENSES	285,886	289,574	598,517	547,278

OPERATING INCOME	138,388	91,063	293,271	185,781

Interest and other income	2,336	889	3,627	1,351
Income from unconsolidated affiliates	1,701	1,675	3,532	3,221
Unrealized mark-to-market loss on basis swaps, net	(5,614)		(5,614)
Loss on early extinguishment of debt	(1,746)		(1,746)
Interest expense	(9,647)	(7,016)	(17,502)	(13,810)

INCOME BEFORE INCOME TAXES	125,418	86,611	275,568	176,543
Income taxes	46,133	31,850	101,618	65,161

NET INCOME	$ 79,285	$ 54,761	$173,950	$ 111,382

See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,	December 31,
	2006	2005
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents		$ 4,350
Notes receivable from Questar	$ 68,200	89,100
Federal income taxes recoverable	10,755	14,136
Accounts receivable, net	156,667	241,714
Accounts receivable from affiliates	21,176	26,386
Derivative collateral deposits		5,150
Fair value of derivative contracts	4,482	1,972
Inventories, at lower of average cost or market
Gas and oil storage	15,854	33,192
Materials and supplies	28,339	24,018
Prepaid expenses and other	21,308	23,348
Deferred income taxes – current	21,330	97,136
Total current assets	348,111	560,502
Property, plant and equipment	3,331,022	3,029,502
Less accumulated depreciation, depletion and amortization	1,197,580	1,095,543
Net property, plant and equipment	2,133,442	1,933,959
Investment in unconsolidated affiliates	33,915	30,681
Goodwill	61,423	61,423
Fair value of derivative contracts	142
Other noncurrent assets	19,499	17,528
	$2,596,532	$2,604,093

LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Checks in excess of cash balances	$ 6,253
Notes payable to Questar	76,100	$ 180,800
Accounts payable and accrued expenses	247,343	349,208
Accounts payable to affiliates	5,051	3,755
Fair value of derivative contracts	28,548	222,049
Total current liabilities	363,295	755,812
Long-term debt	399,171	350,000
Deferred income taxes	482,260	408,399
Asset retirement obligations	79,391	74,273
Fair value of derivative contracts	17,270	99,044
Other long-term liabilities	37,563	42,710
Common shareholder’s equity
Common stock	4,309	4,309
Additional paid-in capital	118,520	116,027
Retained earnings	1,116,921	951,621
Accumulated other comprehensive loss	(22,168)	(198,102)
Total common shareholder’s equity	1,217,582	873,855
	$2,596,532	$2,604,093

See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	6 Months Ended
	June 30,
	2006	2005
	(in thousands)
OPERATING ACTIVITIES
Net income	$173,950	$ 111,382
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	109,037	81,507
Deferred income taxes	42,319	28,058
Share-based compensation	2,493
Abandonment and impairment of gas,
oil and other properties	3,542	2,898
Income from unconsolidated affiliates	(3,532)	(3,221)
Distributed income from unconsolidated affiliates	2,823	2,217
Net (gain) loss from asset sales	(359)	78
Unrealized mark-to-market loss on basis swaps, net	5,614
Loss on early extinguishment of debt	1,746
Ineffective portion of fixed-price swaps	(259)	328
Changes in operating assets and liabilities	1,882	(46,305)
NET CASH PROVIDED FROM
OPERATING ACTIVITIES	339,256	176,942

INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(302,799)	(207,072)
Other investments	(2,525)	(1,842)
Total capital expenditures	(305,324)	(208,914)
Proceeds from disposition of assets	2,708	665
NET CASH USED IN INVESTING ACTIVITIES	(302,616)	(208,249)

FINANCING ACTIVITIES
Checks in excess of cash balances	6,253	857
Change in notes receivable from Questar	20,900	35,300
Change in notes payable to Questar	(104,700)	3,800
Long-term debt issued, net of issue costs	246,953
Long-term debt repaid	(200,000)
Early extinguishment of debt costs	(1,746)
Dividends	(8,650)	(8,650)
NET CASH (USED IN) PROVIDED FROM FINANCING ACTIVITIES	(40,990)	31,307
Change in cash and cash equivalents	(4,350)
Beginning cash and cash equivalents	4,350
Ending cash and cash equivalents	$ -	$ -

See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation of Interim Consolidated Financial Statements

The accompanying unaudited consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) for interim financial information and pursuant to the rules and regulations of the SEC. The consolidated financial statements reflect all normal, recurring adjustments and accruals that are, in the opinion of management, necessary for a fair presentation of financial position and results of operations for the interim periods presented. All significant intercompany accounts and transactions were eliminated in consolidation. Interim consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 1 0-K for the year ended December 31, 2005. Certain reclassifications were made to prior period financial statements to conform with the current presentation.

The preparation of consolidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the six months ended June 30, 2006, are not necessarily indicative of the results that may be expected for the year ending December 31, 2006, due to a variety of factors discussed in the Forward-Looking Statements section of this report.

Note 2 – Share-Based Compensation

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

Questar and the Company implemented SFAS 123R “Share-Based Payment,” effective January 1, 2006 and chose the modified prospective phase-in method of accounting by SFAS 123R. The modified prospective phase-in method requires recognition of compensation costs for all share-based payments granted, modified or settled after January 1, 2006, as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. As a result of adopting SFAS 123R, the Company’s income before income taxes and net income for the six months ended June 30, 2006, were approximately $0.4 million and $0.2 million lower, respectively, than if the Company had continued to account for share-based compensation under APBO 25. The pro forma share-based compensation expense impact for the first half of 2005 was approximately $0.4 million.

Transactions involving stock options granted to employees of Market Resources under the LTSIP are summarized below:

	Outstanding Options	Price Range	Weighted- Average Price

Balance at January 1, 2006	895,319	$15.00 – $77.14	$30.24
Exercised	(74,161)	15.00 – 35.10	21.73
Balance at June 30, 2006	821,158	$15.00 – $77.14	$31.01

The number of unvested stock options held by employees of Market Resources has not changed in the first half of 2006.

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

$15.00 - $17.00	82,534	3.2	$15.89	82,534	$15.89
19.13 - 23.95	273,954	5.1	23.06	273,954	23.06
27.11 - 29.71	350,731	6.0	27.47	289,106	27.49	61,625	$27.37
$35.10 - $77.14	113,939	4.8	72.00	1,439	35.10	112,500	72.47
	821,158	5.2	$31.01	647,033	$24.15	174,125	$56.51

Restricted shares generally vest in three to five years. The average weighted remaining vesting term of unvested restricted shares at June 30, 2006, was three years. Transactions involving restricted shares held by employees of Market Resources are summarized below:

			Weighted Average
	Shares	Price Range	Price

Balance at January 1, 2006	177,241	$27.11 - $86.03	$41.28
Granted	105,040	70.40 - 81.48	72.90
Distributed	(51,580)	27.11 - 64.10	32.79
Forfeited	(1,370)	28.72 - 75.99	57.66
Balance at June 30, 2006	229,331	$27.11 - $86.03	$57.57

Note 3 – Operations by Line of Business

Market Resources has four primary reportable segments: Questar E&P, Wexpro, Gas Management and Energy Trading. Line of business information is presented according to management’s basis for evaluating performance including differences in the nature of products and services. Certain intersegment sales include intercompany profits. Financial information for reportable segments follows:

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
		(in thousands)
REVENUES FROM UNAFFILIATED CUSTOMERS
Questar E&P	$198,385	$137,350	$409,172	$269,847
Wexpro	3,669	3,425	9,972	8,551
Gas Management	40,485	33,148	81,733	62,182
Energy Trading and other	141,571	170,973	298,310	318,654
	$384,110	$344,896	$799,187	$659,234

REVENUES FROM AFFILIATES
Wexpro	$ 36,517	$ 33,204	$ 75,243	$ 66,188
Gas Management	3,434	3,029	7,003	6,201
Energy Trading and other	213	(492)	10,355	1,436
	$ 40,164	$ 35,741	$ 92,601	$ 73,825

OPERATING INCOME
Questar E&P	$104,206	$ 60,518	$222,893	$123,960
Wexpro	18,294	15,871	36,511	31,749
Gas Management	15,104	13,115	29,772	26,058
Energy Trading and other	784	1,559	4,095	4,014
	$138,388	$ 91,063	$293,271	$185,781

NET INCOME
Questar E&P	$ 56,100	$ 34,426	$126,590	$ 70,677
Wexpro	11,957	10,495	23,942	20,677
Gas Management	10,186	8,962	19,924	17,770
Energy Trading and other	1,042	878	3,494	2,258
	$ 79,285	$ 54,761	$173,950	$111,382

Note 4 – Asset Retirement Obligations (ARO)

Market Resources recognizes ARO in accordance with SFAS 143 “Accounting for Asset Retirement Obligations.” SFAS 143 addresses the financial accounting and reporting of the fair value of legal obligations associated with the retirement of tangible long-lived assets. The Company’s ARO applies primarily to plugging and abandonment costs associated with gas and oil wells and certain other properties. The fair value of abandonment costs are estimated and depreciated over the life of the related assets. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Changes in asset retirement obligations were as follows:

	2006	2005
	(in thousands)

Balance at January 1,	$74,273	$66,375
Accretion	2,334	2,009
Additions	3,395	1,326
Retirements and properties sold	(611)	(511)
Balance at June 30,	$79,391	$69,199

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. Accordingly, Wexpro collects from Questar Gas and deposits in trust certain funds related to estimated ARO costs. The funds are used to satisfy retirement obligations as the properties are abandoned. At June 30, 2006, approximately $4.2 million was held in this trust invested primarily in a short-term bond index fund.

Note 5 - Capitalized Exploratory Well Costs

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

	2006
	(in thousands)

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

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

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

Capitalized exploratory well costs that have been capitalized
one year or less	$22,812	$16,514
Capitalized exploratory well costs that have been capitalized
longer than one year
Balance at end of period	$22,812	$16,514

Note 6 – Financing

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

Note 7 – 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 Shareholder’s Equity. Other comprehensive income or loss includes changes in the market value of certain gas- and oil-price hedging arrangements. These results are not reported in current income or loss. Income or loss is realized when the physical gas, oil or NGL underlying the derivative instrument is sold or if the derivative is determined to be ineffective. A summary of comprehensive income is shown below:

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
		(in thousands)

Net income	$ 79,285	$ 54,761	$173,950	$111,382
Other comprehensive income (loss)
Net unrealized gain (loss) on energy hedging contracts	44,406	38,336	283,282	(147,818)
Income taxes	(16,851)	(14,541)	(107,348)	56,230
Net other comprehensive income (loss)	27,555	23,795	175,934	(91,588)
Total comprehensive income	$106,840	$ 78,556	$349,884	$ 19,794

Note 8 - Recent Accounting Developments

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

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

Summary

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

	3 Months Ended			6 Months Ended
	June 30,		%	June 30,			%
	2006	2005	Change	2006		2005	Change
	(in millions)
Net income
Questar E&P	$56.1	$34.4	63%		$126.6	$ 70.7	79%
Wexpro	12.0	10.5	14	23.9		20.7	15
Gas Management	10.2	9.0	13	19.9		17.8	12
Energy Trading and other	1.0	0.9	11	3.5		2.2	59
Market Resources total	$79.3	$54.8	45%	$173.9		$111.4	56%

Results of Operations

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

	3 Months Ended		6 Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
		(in thousands)
OPERATING INCOME
Revenues
Natural gas sales	$165,233	$112,918	$344,074	$221,519
Oil and NGL sales	36,250	27,976	72,966	54,924
Cost-of-service gas operations	34,885	32,020	74,460	65,653
Energy marketing	142,021	171,256	309,264	320,910
Gas gathering, processing and other	45,885	36,467	91,024	70,053
Total revenues	424,274	380,637	891,788	733,059
Operating expenses
Energy purchases	140,274	168,696	303,423	315,229
Operating and maintenance	42,203	36,991	87,590	68,650
General and administrative	15,486	13,335	32,059	27,705
Production and other taxes	20,129	20,962	48,054	42,206
Depreciation, depletion and amortization	54,613	41,257	107,635	81,116
Exploration	10,101	5,476	13,400	6,849
Abandonment and impairment of gas, oil and other properties	1,843	1,493	3,542	2,898
Wexpro Agreement – oil-income sharing	1,237	1,364	2,814	2,625
Total operating expenses	285,886	289,574	598,517	547,278
Operating income	$138,388	$ 91,063	$293,271	$185,781

OPERATING STATISTICS
Questar E&P production volumes
Natural gas (MMcf)	27,561	23,410	56,117	46,249
Oil and NGL (Mbbl)	620	586	1,243	1,169
Total production (Bcfe)	31.3	26.9	63.6	53.3
Average daily production (MMcfe)	344	296	351	294
Questar E&P average realized price, net to the well (including hedges)
Natural gas (per Mcf)	$ 6.00	$ 4.82	$ 6.13	$ 4.79
Oil and NGL (per bbl)	$ 50.11	$ 40.02	$ 50.27	$ 39.38
Wexpro investment base at June 30, net
of depreciation and deferred income taxes (millions)	$ 220.1	$ 188.0
Natural gas gathering volumes (in thousands of MMBtu)
For unaffiliated customers	35,784	33,539	68,434	66,074
For Questar Gas	9,679	11,226	20,242	22,482
For other affiliated customers	16,977	14,416	34,993	30,262
Total gathering	62,440	59,181	123,669	118,818
Gathering revenue (per MMBtu)	$ 0.29	$ 0.25	$ 0.29	$ 0.25
Natural gas and oil marketing volumes (Mdthe)
For unaffiliated customers	25,755	26,347	55,287	55,256
For affiliated customers	24,316	22,095	49,878	44,647
Total marketing	50,071	48,442	105,165	99,903

Questar E&P

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

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

	3 Months Ended				6 Months Ended
	June 30,			%	June 30,			%
	2006*	2005		Change	2006**		2005	Change
	(Bcfe)				(Bcfe)

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

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

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

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

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

17%.

Questar E&P production from the Pinedale Anticline in western Wyoming grew 27% to 17.9 Bcfe in the first six months of 2006 and comprised 28% of Questar E&P total production in the 2006 period. Production at Pinedale typically declines during the first through third quarters of each year due to mid-November to early May seasonal access restrictions imposed by the Bureau of Land Management (BLM) that restrict the company’s ability to drill and complete wells during the period. As a result, Pinedale second quarter 2006 production was 1.5 Bcfe lower than first quarter 2006.

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

Production from Questar E&P Rocky Mountain “Legacy” properties increased 23% to 10.0 Bcfe in the first six months of 2006 compared to a year ago. Excluding one-time adjustments, Legacy production for the first six months of 2006 was 9.0 Bcfe, an increase of 11% over the 2005 period driven by the company’s emerging gas play in the Vermillion Basin. Legacy assets include all Questar E&P Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin.

In the Midcontinent, production grew 26% to 23.3 Bcfe in the first six months of 2006, driven by ongoing infill-development drilling in the Elm Grove field in northwestern Louisiana. Questar E&P midcontinent production also benefited from the December 2005 completion of an exploratory well in the Arkoma Basin of eastern Oklahoma. The well has produced 1.3 Bcfe and has averaged 5.9 MMcfe per day since coming on line. Questar E&P has a 96.2% working interest and an 84.2% net revenue interest in the well before payout of a 200% nonconsent penalty and a 69.5% working interest and a 60.8% net revenue interest after payout.

Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. For the first six months of 2006, the weighted average realized natural gas price for Questar E&P (including the impact of hedging) was $6.13 per Mcf compared to $4.79 per Mcf for the same period in 2005, a 28% increase. Realized oil and NGL prices for the first six months of 2006 averaged $50.27 per bbl, compared with $39.38 per bbl during the prior year period, a 28% increase. A regional comparison of average realized prices, including hedges, is shown in the following table:

	3 Months Ended			6 Months Ended
	June 30,		%	June 30,			%
	2006	2005	Change	2006		2005	Change

Natural gas (per Mcf)
Rocky Mountains	$5.64	$4.67	21%	$5.84	$4.62			26%
Midcontinent	6.54	5.09	28	6.63		5.11	30
Volume-weighted average	6.00	4.82	24	6.13		4.79	28

Oil and NGL (per bbl)
Rocky Mountains	$48.57	$40.42	20%	$48.65		$39.94	22%
Midcontinent	53.57	39.18	37	53.94		38.14	41
Volume-weighted average	50.11	40.02	25	50.27		39.38	28

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

Questar E&P may hedge up to 100 percent of forecasted production from proved reserves to lock in acceptable returns on invested capital and to protect returns, cash flow and net income from a decline in commodity prices. During the second quarter of 2006, Questar E&P continued to take advantage of high natural gas and oil prices to hedge additional production through 2008. The company has and may continue to enter into basis-only swaps to protect cash flows and earnings from a widening of natural gas price basis differentials that may result from capacity constraints on regional gas pipelines. Derivative positions as of June 30, 2006, are summarized in Part I, Item 3 of this quarterly report.

Questar E&P controllable production costs (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense and allocated-interest expense) per Mcfe of production increased 7% to $2.45 per Mcfe compared to the second quarter of 2005. For the first six months of 2006, controllable production costs rose 7% to $2.41 per Mcfe. Questar E&P controllable production costs are summarized in the following table:

	3 Months Ended			6 Months Ended
	June 30,		%	June 30,		%
	2006	2005	Change	2006	2005	Change
	(Per Mcfe)			(Per Mcfe)

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

Depreciation, depletion and amortization expense rose 17% in the second quarter to $1.38 per Mcfe and 15% to $1.33 per Mcfe for the first six months of 2006 due to higher costs for drilling, completion and related services, increased cost of steel casing, other tubulars and wellhead equipment, and the ongoing depletion of older, lower-cost reserves. Per Mcfe lease operating expense decreased slightly as increased costs of materials and consumables were offset by higher production volumes. For the second quarter of 2006, general and administrative expenses fell to $0.27 per Mcfe compared to $0.31 per Mcfe the same period in 2005 due primarily to the reversal of an accrual related to potential legal expense and higher production volumes. For the first six months of 2006, general and administrative expenses fell to $0.31 per Mcfe compared to $0.33 per Mcfe the same period of 2005. Interest expense per Mcfe of production increased in the current quarter due to refinancing activities and a $50 million increase in long-term debt.

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

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

Pinedale Anticline

As of June 30, 2006, Market Resources (both Questar E&P and Wexpro) operated and had working interest in 149 producing wells on the Pinedale Anticline compared to 109 at the end of the second quarter of 2005. Of the 149 producing wells, Questar E&P has working interests in 129 wells, overriding royalty interests only in an additional 19 Wexpro-operated wells, and no interest in one well operated by Wexpro. Wexpro has working interests in 57 of the 149 producing wells. Market Resources expects to complete between 45 and 48 Lance Pool wells (combined Lance and Mesaverde formations) on its Pinedale acreage during 2006.

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

Uinta Basin

During the first six months of 2006, the company drilled or participated in 29 Wasatch and Upper Mesaverde gas wells, 1 horizontal and 1 vertical Green River Formation oil wells, and 2 deeper Blackhawk, Mancos and Dakota formations gas wells on its core acreage block. Questar E&P completed its first deep well designed to test the Mancos and Dakota formations. The well, in which Questar E&P has a 77.5% working interest, averaged approximately 1,100 Mcf per day during its first 90 days online from the deeper section only. Plans call for the well to be completed in uphole zones later this year. A second deep well has been completed in the deeper section and a third is drilling near total depth.

Questar E&P is currently testing several target formations in the Wolf Flat 14C-29-15-19 exploratory well, which is the second well drilled under an Exploration and Development Agreement with the Ute Indian Tribe covering 12,557 acres of tribal minerals in the southern Uinta Basin. Completion operations are underway. Questar E&P has a 75% working interest in the well.

Rockies Legacy

In the Vermillion Basin on the southwest Wyoming-northwest Colorado border, Market Resources continues to evaluate the potential of several formations under the company’s 146,000 net leasehold acres. As of June 30, 2006, the company had recompleted two older wells, drilled and completed seven new wells, one was waiting on completion and two wells were drilling. The targets are the Baxter Shale, which extends across a 3,000-3,500 foot gross interval from about 9,500 feet deep to about 13,000 feet deep on most of the company’s leasehold in the basin, and the deeper Frontier and Dakota tight-sand formations at depths down to 15,000 feet.

Midcontinent

During the second quarter the company continued a one-rig infill-development project in the Elm Grove field in northwest Louisiana as it drilled or participated in nine new wells. On March 31, 2006, Questar E&P acquired interests in 48 producing wells in nine spacing units in the Elm Grove field. The acquisition will provide Questar E&P initial or additional working interest in approximately 75 undrilled locations. The company has added a second drilling rig and plans to participate in about 24 additional Elm Grove wells during the remainder of 2006. In the Hartshorne coalbed-methane project in the Arkoma Basin of eastern Oklahoma, the company drilled or participated in six new wells in the first half of 2006 and anticipates participating in an additional three wells during the remainder of 2006.

Wexpro

Wexpro, a subsidiary that develops and produces cost-of-service reserves for Questar Gas, reported net income was $12.0 million, compared with $10.5 million for the same period in 2005, a 14% increase. For the first six months of 2006 Wexpro net income was $23.9 million, compared with $20.7 million for the same period in 2005, a 15% increase. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19% to 20% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation (investment base). Wexpro investment base at June 30, 2006, increased 17% to $220.1 million up $32.1 million over the year earlier period. Wexpro net income also benefited from 31% higher realized oil and NGL prices versus the second quarter of 2005.

Gas Management

Gas Management, a gas-gathering and processing-services business, grew net income 13% to $10.2 million in the second quarter of 2006 from $9.0 million in the 2005 period. Net income for the first six months of 2006 was $19.9 million versus $17.8 million for the same period in 2005, a 12% increase. Gas processing plant margin grew 63% from $12.6 million in the first half of 2005 to $20.5 million in the first half of 2006. NGL sales volumes in the first six months of 2006 increased 11% versus the year earlier period, primarily as a result of increased throughput at a gas processing plant in western Wyoming acquired in the first quarter of 2005. Gathering volumes increased 4.9 million MMBtu to 123.7 million MMBtu in the first six months of 2006 due primarily to expanding Pinedale production and new projects serving third parties in the Uinta Basin. Total gathering margins decreased primarily due to start-up co sts associated with the Pinedale liquids-gathering and transportation facilities.

To reduce processing margin risk, Gas Management has restructured a number of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. A keep-whole contract protects producers from frac spread risk while fee-based contracts eliminate commodity-price risk for the plant owner. In the first six months of 2006 keep-whole contracts benefited from a 26% increase in realized NGL sales prices versus the prior-year period. Fee-based contracts were impacted by a $0.03 decrease in the rate charged per MMBtu processed in the first half comparable periods. To further reduce margin volatility associated with keep-whole contracts, Gas Management began managing NGL price risk in 2004 by using forward-sales contracts. Forward sales contracts increased NGL revenues by $1.3 million in 2006.

Income before tax from Gas Management’s 50% interest in Rendezvous Gas Services, LLC, (Rendezvous), a joint venture that operates gas-gathering facilities in western Wyoming, increased to $3.3 million for the first six months of 2006 versus $3.1 million for 2005, a 6% increase. Income growth in Rendezvous was driven by increased gathering volumes. Rendezvous provides gas gathering services for the Pinedale and Jonah producing areas. Gas Management continues to invest in additional gas gathering and processing and liquids-handling facilities to serve growing equity and third-party production in its core areas of the Pinedale and Jonah fields in western Wyoming and the Uinta Basin in eastern Utah.

Energy Trading and Other

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

Consolidated Results after Operating Income

Income from unconsolidated affiliates

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

Interest expense and loss on early extinguishment of debt

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

Unrealized mark-to-market loss on basis swaps

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

Income taxes

The effective combined federal and state income tax rate was 36.9% in the first half of both 2006 and 2005.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

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

Commodity-Price Risk Management

Market Resources bears the risk associated with commodity-price changes and uses gas- and oil-price-derivative arrangements in the normal course of business to limit the risk of adverse price movements. However these same arrangements typically limit future gains from favorable price movements. Derivative contracts are used for a significant share of Questar E&P-owned gas and oil production, a portion of Energy Trading gas- and oil-marketing transactions and some of Gas Management’s NGL.

Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. Natural gas- and oil-price hedging supports the Company’s 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 Company’s Board of Directors. Market Resources may hedge up to 100% of forecast production from proved reserves when prices meet earnings and cash flow objectives. Market Resources does not enter into derivative arrangements for speculative purposes and does not hedge undeveloped reserves or equity NGL.

Generally derivative instruments are matched to equity gas and oil production, thus qualifying as cash flow hedges under the accounting provisions of SFAS 133 as amended and interpreted. Changes in the fair value of cash-flow hedges are recorded on the balance sheet and in other comprehensive income or loss until the underlying gas or oil is produced. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. The ineffective portion of cash flow hedges is immediately recognized in the determination of net income. The ineffective portion of cash flow hedges was not significant in the first half of 2006 or 2005.

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

Market Resources enters into commodity price derivative arrangements with several banks and energy-trading firms with a variety of credit requirements. Some contracts do not require collateral deposits, while others allow some amount of credit before Market Resources is required to deposit collateral for out-of-the-money contracts. The amount of credit available may vary depending on the credit rating assigned to Market Resources debt. In addition to the counterparty arrangements, Market Resources has a $200 million long-term revolving-credit facility with banks with no borrowings outstanding at June 30, 2006.

A summary of Market Resources derivative positions for equity production as of June 30, 2006, is shown below. Currently fixed-price and basis-only swaps are with creditworthy counterparties. Prices for fixed-price swaps, allow Market Resources to realize a known price for a specific volume of production delivered into a regional sales point. The fixed price swap price is then reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price:

	Rocky			Rocky
Time Periods	Mountains	Midcontinent	Total	Mountains	Midcontinent	Total
				Estimated
	Gas (in Bcf) Fixed-Price Swaps			Average price per Mcf, net to the well
2006
Second half	26.1	12.2	38.3	$5.93	$6.81	$6.21

2007
First half	19.8	10.1	29.9	$7.02	$7.82	$7.29
Second half	20.1	10.3	30.4	7.02	7.82	7.29
12 months	39.9	20.4	60.3	7.02	7.82	7.29

2008
First half	13.5	6.9	20.4	$7.20	$8.06	$7.49
Second half	13.7	6.9	20.6	7.20	8.06	7.49
12 months	27.2	13.8	41.0	7.20	8.06	7.49

	Gas (in Bcf) Basis-Only Swaps			Estimated Average basis per Mcf vs. NYMEX
2006
Second half	8.3		8.3	$2.07		$2.07

2007
First half	6.7		6.7	$1.96		$1.96
Second half	6.9		6.9	1.96		1.96
12 months	13.6	0.0	13.6	1.96		1.96

2008
First half	10.2		10.2	$1.64		$1.64
Second half	10.3		10.3	1.64		1.64
12 months	20.5	0.0	20.5	1.64		1.64

	Oil (in Mbbl) Fixed-Price Swaps			Average price per bbl, net to the well
2006
Second half	626	202	828	$47.77	$59.89	$50.73

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

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

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

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

	Fixed-Price Swaps	Basis-Only Swaps	Total
	(in thousands)

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

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

	Fixed-Price Swaps	Basis-Only Swaps	Total
	(in thousands)

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

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

	At June 30,
	2006	2005
	(in millions)

Mark-to-market valuation – liability	($41.2)	($215.6)
Value if market prices of gas and oil and basis differentials decline by 10%	87.8	(105.8)
Value if market prices of gas and oil and basis differentials increase by 10%	(171.3)	(325.5)

Interest-Rate Risk Management

As of June 30, 2006, Market Resources had $399.2 million of fixed-rate long-term debt.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures.

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

Changes in Internal Controls.

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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

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

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

Environmental Claims. In 2004, the Environmental Protection Agency (EPA) issued two separate compliance orders alleging that Gas Management did not comply with regulatory requirements adopted to enforce the federal Clean Air Act. Both orders involved facilities in the Uinta Basin of eastern Utah that were purchased by Questar E&P in mid-2001. Gas Management believes it is operating the facilities and filing necessary reports in compliance with regulatory requirements; however, the EPA contends such facilities are located within Indian Country and are subject to additional Clean Air Act requirements not applicable to non-Indian Country lands administered by the state of Utah. As a consequence, EPA has broadened its allegations to include additional potential ongoing violations of the Clean Air Act for the referenced facilities. Other Gas Management facilities in the Uinta Basin have been added to the civil penalty discussions with the EPA, with similar allegations of Clean Air Act violations. These potential violations will likely result in civil penalties of an unknown and undetermined amount but in excess of $100,000.

Item 6. Exhibits

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

Exhibit No.

Exhibits

1.1.*

Purchase Agreement, dated May 11, 2006, by and among Questar Market Resources, Inc., and named Underwriters. (Incorporated by reference to Exhibit 99.1 to the Company’s current report on Form 8-K filed with the Securities and Exchange Commission on May 11, 2006.)

4.1.*

Form of the Registrant’s 6.05% Note due 2016. (Incorporated by reference to Exhibit 99.2 to the Company’s current report on Form 8-K filed with the Securities and Exchange Commission on May 11, 2006.)

4.2.*

Form of Officers’ Certificate setting forth the terms of the 6.05% Notes. (Incorporated by reference to Exhibit 99.3 to the Company’s current report on Form 8-K filed with the Securities and Exchange Commission on May 11, 2006.)

10.1

Fourth Amendment to Credit Agreement dated July 27, 2006, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders.

12.

Ratio of earnings to fixed charges.

31.1.

Certification signed by Charles B. Stanley, Questar Market Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2.

Certification signed by S. E. Parks, Questar Market Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.

Certification signed by Charles B. Stanley and S. E. Parks, Questar Market Resources, Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*Exhibits so marked have been filed with the Securities and Exchange Commission as part of the referenced filing and are incorporated herein by reference.

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 MARKET RESOURCES, INC.

(Registrant)

August 4, 2006

/s/Charles B. Stanley

Charles B. Stanley

President and Chief Executive Officer

August 4, 2006

/s/S. E. Parks

S. E. Parks

Vice President and Chief Financial Officer

Exhibits List

Exhibits

1.1.*

4.1.*

4.2.*

10.1

Fourth Amendment to Credit Agreement dated July 27, 2006, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders.

12.

Ratio of earnings to fixed charges.

31.1.

Certification signed by Charles B. Stanley, Questar Market Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2.

Certification signed by S. E. Parks, Questar Market Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.

*Exhibits so marked have been filed with the Securities and Exchange Commission as part of the referenced filing and are incorporated herein by reference.

Exhibit 10.1.

FOURTH AMENDMENT TO CREDIT AGREEMENT

THIS FOURTH AMENDMENT TO CREDIT AGREEMENT (herein called the “Amendment”) made as of July 27, 2006 by and among QUESTAR MARKET RESOURCES, INC., a Utah corporation (“Borrower”), BANK OF AMERICA, N.A., individually and as administrative agent (“Administrative Agent”), and the Lenders party to the Original Agreement defined below (“Lenders”).

W I T N E S S E T H:

WHEREAS, Borrower, Administrative Agent and Lenders entered into that certain Credit Agreement dated as of March 19, 2004, (as amended by (i) that certain First Amendment to Credit Agreement dated as of October 25, 2004, (ii) that certain Second Amendment to Credit Agreement dated as of August 9, 2005, and (iii) that certain Third Amendment to Credit Agreement dated as of September 20, 2005, the “Original Agreement”), for the purpose and consideration therein expressed, whereby Lenders became obligated to make loans to Borrower as therein provided; and

WHEREAS, Borrower, Administrative Agent and Lenders desire to further amend the Original Agreement as set forth herein;

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement, in consideration of the loans which may hereafter be made by Lenders to Borrower, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows:

ARTICLE I.

DEFINITIONS AND REFERENCES

1.1

Terms Defined in the Original Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this Amendment.

1.2

Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this Section 1.2.

“Amendment” means this Fourth Amendment to Credit Agreement.

“Credit Agreement” means the Original Agreement as amended hereby.

ARTICLE II.

AMENDMENT TO ORIGINAL AGREEMENT

2.1

Defined Terms. The following definitions in Section 1.01 of the Original Agreement are hereby amended in their entirety to read as follows:

“Applicable Rate” means, from time to time, the following percentages per annum, based upon the Debt Rating as set forth below:

Applicable Rate
Pricing Level	Debt Ratings S&P/Moody’s	Commitment Fee	Eurodollar Rate Letters of Credit Fee	Utilization Fee
1	≥A-/A3	0.080%	0.300%	0.100%
2	BBB+/Baa1	0.100%	0.350%	0.100%
3	BBB/Baa2	0.115%	0.450%	0.100%
4	BBB-/Baa3	0.140%	0.550%	0.150%
5	≤BB+/Ba1	0.160%	0.750%	0.250%

“Aggregate Commitments” means the Commitments of all the Lenders in an amount not to exceed $182,000,000, except as such amount may be increased pursuant to Section 2.13.”

“Maturity Date” means the later of (a) August 9, 2011, and (b) if maturity is extended pursuant to Section 2.14, such extended maturity date as determined pursuant to section 2.14 (it being understood and agreed that any such maturity shall not be deemed extended for any Lender that has not consented to such extension).

2.2

Schedules. Schedule 2.01 attached to this Amendment immediately following the signature pages is hereby substituted for Schedule 2.01 to the Original Agreement.

ARTICLE III.

CONDITIONS TO EFFECTIVENESS

3.1

Effective Date. This Amendment shall become effective as of the date first above written (the “Effective Date”) when and only when:

(a)

Administrative Agent shall have received all of the following, at Administrative Agent's office, duly executed and delivered and in form and substance satisfactory to Administrative Agent:

(i)

this Amendment;

(ii)

an opinion of counsel with respect to the due authorization, execution and delivery of this Amendment, and the enforceability of the Original Agreement as amended by this Amendment, by and against the Borrower and covering such other matters as may be reasonably requested by Administrative Agent in a form acceptable to Administrative Agent;

(iii)

a certificate of a Responsible Officer of Borrower dated the date of this Amendment certifying: (i) that resolutions adopted by the Board of Directors of the Borrower authorize the execution, delivery and performance of this Amendment by Borrower and the extension of the Maturity Date as provided in this Amendment; (ii) the names and true signatures of the officers of the Borrower authorized to sign this Amendment; (iii) that all of the representations and warranties set forth in Article V of the Original Agreement are true and correct at and as of the Effective Date (or, if any such representation or warranty is expressly stated to have been made as of a specific date, as of such specific date); (iv) that no Default or Event of Default shall have occurred and be continuing at and as of the Effective Date and no Default or Event of Default shall occur as a result o f the extension of the Maturity Date by this Amendment; and (v) no event has occurred since the date of the most recent audited financial statements of the Borrower delivered pursuant to Section 6.02(a) and (b) of the Original Agreement that has had, or could reasonably be expected to have, a Material Adverse Effect; and

(iv)

such other supporting documents as Administrative Agent may reasonably request.

(b)

Borrower shall have paid, in connection with such Loan Documents, all recording, handling, amendment and other fees and reimbursements required to be paid to Administrative Agent pursuant to any Loan Documents, or otherwise due Administrative Agent and including fees and disbursements of Administrative Agent’s attorneys.

ARTICLE IV.

REPRESENTATIONS AND WARRANTIES

4.1

Representations and Warranties of Borrower. In order to induce each Lender to enter into this Amendment, Borrower represents and warrants to each Lender that:

(a)

The representations and warranties contained in Article V of the Original Agreement are true and correct at and as of the time of the effectiveness hereof, (or if any such representation or warranty is made as of a specific date as of such specific date).

(b)

Borrower is duly authorized to execute and deliver this Amendment and is and will continue to be duly authorized to borrow monies and to perform its obligations under the Credit Agreement. Borrower has duly taken all corporate action necessary to authorize the execution and delivery of this Amendment and to authorize the performance of the obligations of Borrower hereunder.

(c)

The execution and delivery by Borrower of this Amendment, the performance by Borrower of its obligations hereunder and the consummation of the transactions contemplated hereby do not and will not conflict with any provision of law, statute, rule or regulation or of the articles of incorporation and bylaws of Borrower, or of any material agreement, judgment, license, order or permit applicable to or binding upon Borrower, or result in the creation of any lien, charge or encumbrance upon any assets or properties of Borrower. Except for those which have been obtained, no consent, approval, authorization or order of any court or governmental authority or third party is required in connection with the execution and delivery by Borrower of this Amendment or to consummate the transactions contemplated hereby.

(d)

When duly executed and delivered, each of this Amendment and the Credit Agreement will be a legal and binding obligation of Borrower, enforceable in accordance with its terms, except as limited by bankruptcy, insolvency or similar laws of general application relating to the enforcement of creditors' rights and by equitable principles of general application.

(e)

The audited annual consolidated financial statements of Borrower dated as of December 31, 2005 and the unaudited quarterly consolidated financial statements of Borrower dated as of March 31, 2006 fairly present the consolidated financial position at such dates and the consolidated results of operations and the changes in consolidated financial position for the periods ending on such dates for Borrower. Copies of such consolidated financial statements have heretofore been delivered to each Lender. Since such dates no material adverse change has occurred in the consolidated financial condition or businesses of Borrower.

ARTICLE V.

MISCELLANEOUS

5.1

Ratification of Agreements. The Original Agreement as hereby amended is hereby ratified and confirmed in all respects. Any reference to the Credit Agreement in any Loan Document shall be deemed to be a reference to the Original Agreement as hereby amended. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of Lenders under the Credit Agreement, the Notes, or any other Loan Document nor constitute a waiver of any provision of the Credit Agreement, the Notes or any other Loan Document.

5.2

Survival of Agreements. All representations, warranties, covenants and agreements of Borrower herein shall survive the execution and delivery of this Amendment and the performance hereof, including without limitation the making or granting of the Loans, and shall further survive until all of the Obligations are paid in full. All statements and agreements contained in any certificate or instrument delivered by Borrower hereunder or under the Credit Agreement to any Lender shall be deemed to constitute representations and warranties by, and/or agreements and covenants of, Borrower under this Amendment and under the Credit Agreement.

5.3

Loan Documents. This Amendment is a Loan Document, and all provisions in the Credit Agreement pertaining to Loan Documents apply hereto.

5.4

Governing Law. This Amendment shall be governed by and construed in accordance the laws of the State of New York and any applicable laws of the United States of America in all respects, including construction, validity and performance.

5.5

Counterparts; Fax. This Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. This Amendment may be validly executed by facsimile or other electronic transmission.

THIS AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS OF THE PARTIES.

[The remainder of this page has been intentionally left blank.]

IN WITNESS WHEREOF, this Amendment is executed as of the date first above written.

		QUESTAR MARKET RESOURCES, INC.

		/s/Charles B. Stanley
		Charles B. Stanley President and Chief Executive Officer

		BANK OF AMERICA, N.A., as Administrative Agent

		/s/Jennifer Reeves
		Jennifer Reeves Agency Management

		BANK OF AMERICA, N.A., as a Lender and L/C Issuer

		/s/Zewditu Menelik
		Zewditu Menelik Vice President

		BMO CAPITAL MARKETS FINANCING, INC., as a Lender

		/s/Cahal Carmody
		Cahal Carmody Vice President

		WELLS FARGO BANK, NA, as Co-Syndication Agent and a Lender

		/s/Troy S. Akagi
		Troy S. Akagi Vice President

		SUNTRUST BANK, as Co-Documentation Agent and a Lender

		/s/Kelley Brandenburg
		Kelley Brandenburg Vice President

		JP MORGAN CHASE BANK, N.A., as Co-Documentation Agent and a Lender

		/s/Robert W. Traband
		Robert W. Traband Vice President

		WACHOVIA BANK, NATIONAL ASSOCIATION, as a Lender

		/s/Paul Pritchett
		Paul Pritchett Vice President

		THE BANK OF TOKYO, MITSUBISHI, LTD., as a Lender

		/s/John McGee
		John McGee Vice President & Manager



		/s/Jay Fort
		Jay Fort Vice President

		BARCLAYS BANK PLC, as a Lender

		/s/Nicholas Bell
		Nicholas Bell Director

		THE ROYAL BANK OF SCOTLAND plc, as a Lender

		/s/David Slye
		David Slye Vice President

SCHEDULE 2.01

COMMITMENTS AND PRO RATA SHARES

Questar Market Resources Bank Group
Lender	Commitment	% Comm

Bank of America, N.A.	$22,000,000	12.087912088%
Harris Nesbitt Financing, Inc.	$22,000,000	12.087912088%
Wells Fargo Bank, NA	$22,000,000	12.087912088%
SunTrust Banks, Inc.	$22,000,000	12.087912088%
JPMorgan Chase Bank, N.A.	$22,000,000	12.087912088%
Wachovia Bank, National Association	$18,000,000	9.890109890%
The Bank of Tokyo-Mitsubishi, Ltd.	$18,000,000	9.890109890%
Barclays Bank PLC	$18,000,000	9.890109890%
The Royal Bank of Scotland plc	$18,000,000	9.890109890%


Total Commitment	$182,000,000	100%

Exhibit 12.

Questar Market Resources, Inc.

Ratio of Earnings to Fixed Charges

(Unaudited)

	6 Months Ended June 30,
	2006	2005
	(dollars in thousands)
Earnings

Income before income taxes	$275,568	$176,543
Less Company’s share of income of
unconsolidated affiliates	(3,532)	(3,221)
Plus distributed income of unconsolidated
affiliates	2,823	2,217
Plus interest expense	17,502	13,810
Plus interest portion of rental expense	594	568
	$292,955	$189,917

Fixed Charges

Interest expense	$17,502	$ 13,810
Plus interest portion of rental expense	594	568
	$18,096	$ 14,378

Ratio of Earnings to Fixed Charges	16.19	13.21

For purposes of this presentation, earnings represent income before income taxes adjusted for fixed charges, earnings and distributed income of equity investees and the amortization of capitalized interest, if any. Fixed charges consist of total interest charges (expensed or capitalized), amortization of debt issuance costs and the interest portion of rental costs (which is estimated at 50%). Income before income taxes includes our share of pretax earnings of equity investees.

Exhibit 31.1.

CERTIFICATION

I, Charles B. Stanley, certify that:

I have reviewed this quarterly report of Questar Market Resources, Inc. on Form 10-Q for the period ending June 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)) 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;

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

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

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

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

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

August 4, 2006

/s/Charles B. Stanley

Charles B. Stanley

President and Chief Executive Officer

Exhibit 31.2.

CERTIFICATION

I, S. E. Parks, certify that:

I have reviewed this quarterly report of Questar Market Resources, Inc. on Form 10-Q for the period ending June 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.

August 4, 2006

/s/S. E. Parks

S. E. Parks

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 Market Resources, Inc. (the Company) on Form 10-Q for the period ending June 30, 2006, as filed with the Securities and Exchange Commission on the date hereof (the Report), Charles B. Stanley, President and Chief Executive Officer of the Company, and S. E. Parks, 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 MARKET RESOURCES, INC.

August 4, 2006

/s/Charles B. Stanley

Charles B. Stanley

President and Chief Executive Officer

August 4, 2006

/s/S. E. Parks

S. E. Parks

Vice President and Chief Financial Officer