UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

The Securities Exchange Act of 1934

Date of Report – June 3, 2009

(Date of earliest event reported)

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

STATE OF UTAH	000-30321	87-0287750
(State or other jurisdiction of incorporation)	(Commission File No.)	(I.R.S. Employer 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

                                  Not Applicable                                  

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

[  ]  Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[  ]  Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[  ]  Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17

       CFR 240.14d-2(b))

[  ]  Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17

       CFR 240.13e-4(c))

Item 8.01    Other Events

This Current Report on Form 8-K is being filed by Questar Market Resources, Inc. (Market Resources or Company) to update certain portions of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, filed on February 27, 2009 (2008 Form 10-K), to reflect the retrospective application upon adoption, effective January 1, 2009, of Statement of Financial Accounting Standards (SFAS) 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”.

On January 1, 2009, Market Resources adopted SFAS 160. SFAS 160 requires noncontrolling ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the Consolidated Balance Sheets within equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the Consolidated Statements of Income; changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently; and any retained noncontrolling equity investment in a former subsidiary be initially measured at fair value.

The following Items of the 2008 Form 10-K are being updated retrospectively to reflect the adoption of the accounting pronouncement described above (which Items as updated are included in Exhibit 99.1 hereto and hereby incorporated by reference herein):

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Item 8.  Financial Statements and Supplementary Data.

No Items of the 2008 Form 10-K other than those identified above are being updated by this filing. Information in the 2008 Form 10-K is generally stated as of December 31, 2008, and this filing does not reflect any subsequent information or events other than the adoption of the accounting pronouncement described above. Without limitation of the foregoing, this filing does not purport to update Management’s Discussion and Analysis of Financial Condition and Results of Operation contained in the 2008 Form 10-K for any information, uncertainties, transactions, risks, events or trends occurring, or known to management. More current information is contained in the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009 (Form 10-Q), and its other filings with the Securities and Exchange Commission. This Current Report on Form 8-K should be read in conjunction with the 2008 Form 10-K, the Form 10-Q and the Company’s other filings. The Form 10-Q and other filings contain important information regarding events, developments and updates to certain expectations of the Company that have occurred subsequent to the filing of the 2008 Form 10-K.

Item 9.01

Financial Statements and Exhibits.

Exhibits.

Exhibit No.

Exhibit

     23.1

Consent of Ernst & Young LLP

     99.1

Updated financial information as of December 31, 2008 and 2007and for each of the three years ended December 31, 2008.

     99.2

Ratio of earnings to fixed charges

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SIGNATURE

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 hereunto duly authorized.

QUESTAR MARKET RESOURCES, INC.

(Registrant)

Date: June 3, 2009

/s/Richard J. Doleshek

 

Richard J. Doleshek

Executive Vice President & CFO

List of Exhibits:

Exhibits.

Exhibit No.

Exhibit

     23.1

Consent of Ernst & Young LLP

     99.1

Updated financial information as of December 31, 2008 and 2007and for each of the three years ended December 31, 2008.

     99.2

Ratio of earnings to fixed charges

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference into the Registration Statements on Form S-3 (No. 333-149589 and 333-153818) of Questar Market Resources of our report dated February 24, 2009 (except for Note 16 as to which the date is May 29, 2009) with respect to the consolidated financial statements of Questar Market Resources, included in this Form 8-K, filed with the Securities and Exchange Commission.

/s/ Ernst & Young LLP

May 29, 2009

Salt Lake City, Utah

Exhibit 99.1

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION.

SUMMARY

Net income attributable to Market Resources increased 39% in 2008 compared to 2007 and 18% in 2007 over 2006 primary due to higher realized natural gas, crude oil and NGL prices, higher gathering and processing margins at Gas Management and an increased investment base at Wexpro.

Following are comparisons of net income attributable to Market Resources by line of business:

	Year Ended December 31,			Change
	2008	2007	2006	2008 vs. 2007	2007 vs. 2006
	(in millions)
Exploration and Production
Questar E&P	$408.0	$285.5	$253.9	$122.5	$31.6
Wexpro	73.9	59.2	50.0	14.7	9.2
Midstream Field Services – Gas Management	81.5	55.3	42.6	26.2	12.7
Energy Marketing – Energy Trading, and other	22.1	20.8	9.6	1.3	11.2
Net income attributable to Market Resources	$585.5	$420.8	$356.1	$164.7	$64.7

RESULTS OF OPERATIONS

EXPLORATION AND PRODUCTION

Questar E&P

Following is a summary of Questar E&P financial and operating results:

	Year Ended December 31,			Change
	2008	2007	2006	2008 vs. 2007	2007 vs. 2006
	(in millions)
Operating Income
REVENUES
Natural gas sales	$1,147.7	$786.9	$681.6	$360.8	$105.3
Oil and NGL sales	237.5	164.2	128.6	73.3	35.6
Other	6.9	4.9	5.5	2.0	(0.6)
Total Revenues	1,392.1	956.0	815.7	436.1	140.3
OPERATING EXPENSES
Operating and maintenance	125.4	87.9	73.6	37.5	14.3
General and administrative	55.8	56.3	42.4	(0.5)	13.9
Production and other taxes	104.0	60.1	58.3	43.9	1.8
Depreciation, depletion and amortization	330.9	243.5	185.7	87.4	57.8
Exploration	29.3	22.0	34.4	7.3	(12.4)
Abandonment and impairment	44.6	10.8	7.6	33.8	3.2
Natural gas purchases	0.5	2.2	2.8	(1.7)	(0.6)
Total Operating Expenses	690.5	482.8	404.8	207.7	78.0
Net gain (loss) from asset sales	60.4	(0.6)	24.3	61.0	(24.9)
Operating Income	$  762.0	$472.6	$435.2	$289.4	$  37.4
Operating Statistics

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Production Volumes
Natural gas (Bcf)	151.9	121.9	113.9	30.0	8.0
Oil and NGL (MMbbl)	3.3	3.0	2.6	0.3	0.4
Total production (Bcfe)	171.4	140.2	129.6	31.2	10.6
Average daily production (MMcfe)	468.3	384.1	355.2	84.2	28.9
Average realized price, net to the well (including hedges)
Natural gas (per Mcf)	$   7.56	$   6.45	$   5.98	$  1.11	$   0.47
Oil and NGL (per bbl)	72.96	53.99	49.12	18.97	4.87

Questar E&P reported net income of $408.0 million in 2008, up 43% from $285.5 million in 2007 and $253.9 million in 2006. Higher realized natural gas, crude oil and NGL prices and growing production more than offset a 17% increase in 2008 average production costs. Net mark-to-market losses on natural gas basis-only hedges decreased pre-tax income $79.2 million in 2008 compared to net pre-tax gains of $5.7 million a year-earlier. Net gains from sales of assets at Questar E&P increased pre-tax income $60.4 million in 2008 compared to a net pre-tax loss of $0.6 million in the year-earlier period.

Questar E&P production volumes totaled 171.4 Bcfe in 2008 compared to 140.2 Bcfe in 2007 and 129.6 Bcfe in 2006. On an energy-equivalent basis, natural gas comprised approximately 89% of Questar E&P 2008 production. A comparison of natural gas-equivalent production by major operating area is shown in the following table:

	Year Ended December 31,			Change
	2008	2007	2006	2008 vs. 2007	2007 vs. 2006
	(in Bcfe)
Pinedale Anticline	56.8	47.4	39.5	9.4	7.9
Uinta Basin	26.9	25.4	25.1	1.5	0.3
Rockies Legacy	19.9	16.4	18.3	3.5	(1.9)
Rocky Mountain total(a)	103.6	89.2	82.9	14.4	6.3
Midcontinent	67.8	51.0	46.7	16.8	4.3
Total Questar E&P	171.4	140.2	129.6	31.2	10.6

^(a)Questar E&P temporarily shut in approximately 1.4 Bcfe of net production in 2008 and 10.3 Bcfe in 2007 in the Rocky Mountain region in response to low natural gas prices.

Questar E&P net production from the Pinedale Anticline in western Wyoming grew 20% to 56.8 Bcfe in 2008 as a result of ongoing development drilling. Historically, Pinedale seasonal access restrictions imposed by the Bureau of Land Management have limited the ability to drill and complete wells during the mid-November to early May period. In September 2008, the BLM issued a Record of Decision (ROD) on the Final Supplemental Environmental Impact Statement for long-term development of natural gas resources in the Pinedale Anticline Project Area (PAPA). Under the ROD, Questar E&P and Wexpro will be allowed to drill and complete wells year-round in one of the five Concentrated Development Areas defined in the PAPA. The ROD contains additional requirements and restrictions on development of the PAPA.

In the Uinta Basin, Questar E&P’s net production grew 6% to 26.9 Bcfe in 2008. Production volumes were adversely impacted by connection of new, deep, high-pressure wells to the existing gathering infrastructure. Connection of the new deep wells resulted in high gathering-system pressure that negatively impacted production from existing shallower and lower pressure Wasatch/Mesaverde wells. Gathering infrastructure improvements are underway to address the situation, but right-of-way permitting issues could delay installation until mid 2009.

Rockies Legacy net production in 2008 grew 21% to 19.9 Bcfe, 3.5 Bcfe higher than the year-ago period. Increased production volumes were driven by new wells and the acquisition of additional interests in the Wamsutter area of the Green River Basin in Wyoming, and increased production from outside-operated oil wells in the Williston Basin in North Dakota. Questar E&P Rockies Legacy properties include all Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin.

Net production in the Midcontinent grew 33% to 67.8 Bcfe in 2008, 16.8 Bcfe higher than 2007. Midcontinent production growth was driven by the first quarter 2008 acquisition of new natural gas development properties in northwest Louisiana, ongoing infill-development drilling in the Elm Grove field in northwest Louisiana, continued development of the Granite Wash/Atoka/Morrow

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play in the Texas Panhandle, and production from new outside-operated Woodford Shale horizontal gas wells in the Anadarko Basin in central Oklahoma.

Realized prices for natural gas, oil and NGL at Questar E&P were higher when compared to the prior year. In 2008, the weighted-average realized natural gas price for Questar E&P (including the impact of hedging) was $7.56 per Mcf compared to $6.45 per Mcf in 2007, a 17% increase. Realized oil and NGL prices in 2008 averaged $72.96 per bbl, compared with $53.99 per bbl during the prior year, a 35% increase. A regional comparison of average realized prices, including hedges, is shown in the following table:

	Year Ended December 31,			Change
	2008	2007	2006	2008 vs. 2007	2007 vs. 2006
Natural gas (per Mcf)
Rocky Mountains	$6.85	$5.90	$5.70	$0.95	$0.20
Midcontinent	8.63	7.42	6.46	1.21	0.96
Volume-weighted average	7.56	6.45	5.98	1.11	0.47
Oil and NGL (per bbl)
Rocky Mountains	$73.05	$53.51	$46.62	$19.54	$6.89
Midcontinent	72.82	54.85	54.93	17.97	(0.08)
Volume-weighted average	72.96	53.99	49.12	18.97	4.87

Questar E&P may hedge up to 100% of forecasted production from proved reserves to lock in acceptable returns on invested capital and to protect cash flow and net income from a decline in commodity prices. Also, Questar E&P may use 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. Questar E&P hedged or pre-sold approximately 82% of gas production in 2008 and hedged or pre-sold 75% of gas production in 2007. Hedging increased Questar E&P gas revenues by $125.8 million in 2008 and increased revenues $245.7 million in 2007. Approximately 50% of 2008 and 61% of 2007 Questar E&P oil production was hedged or pre-sold. Oil hedges reduced oil revenues by $31.9 million in 2008 and $17.2 million in 2007. The net mark-to-market effect of basis-only swaps is reported in the Consolidated Statements of Income below operating income. Derivative positions as of December 31, 2008, are summarized in Item 7A of Part II in this Annual Report on Form 10-K.

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 17% to $3.94 per Mcfe in 2008 versus $3.38 per Mcfe in 2007. Questar E&P production costs are summarized in the following table:

	Year Ended December 31,			Change
	2008	2007	2006	2008 vs. 2007	2007 vs. 2006
	(per Mcfe)
Depreciation, depletion and amortization	$1.93	$1.74	$1.43	$0.19	$0.31
Lease operating expense	0.73	0.63	0.57	0.10	0.06
General and administrative expense	0.33	0.40	0.33	(0.07)	0.07
Allocated interest expense	0.34	0.18	0.21	0.16	(0.03)
Production taxes	0.61	0.43	0.45	0.18	(0.02)
Total Production Costs	$3.94	$3.38	$2.99	$0.56	$0.39

Production volume-weighted average depreciation, depletion and amortization per Mcfe (DD&A rate) increased due to higher costs for drilling, completion and related services, increased cost of steel casing, other tubulars and wellhead equipment. The DD&A rate also increased due to the ongoing depletion of older, lower-cost reserves and the increasing component of Questar E&P production derived from recently acquired, higher-cost fields in the Midcontinent. Lease operating expense per Mcfe increased due to higher costs of materials and consumables, increased produced-water disposal costs and increased well-workover activity. General and administrative expense per Mcfe decreased as a result of increased production. Allocated interest expense per Mcfe of production increased primarily due to financing costs related to the first quarter 2008 acquisition of natural gas development properties in northwest Louisiana. Production taxes per Mcfe increased in 2008 as the result higher n atural gas and oil sales prices. The company pays production taxes based on a percentage of sales prices excluding the impact of hedges.

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Questar E&P exploration expense increased $7.3 million or 33% in 2008 compared to 2007. Abandonment and impairment expense increased $33.8 million or 313% in 2008 compared to 2007. Abandonment and impairment expense increased $29.9 million in the fourth quarter of 2008 compared with the same period of 2007. Lower year-end 2008 gas and oil prices triggered impairment testing of long-lived assets. Future cash flows using estimated forward-looking commodity prices were sufficient to recover the investment of a majority of the long-lived assets. A combination of poor production performance, higher production costs and negative reserve revisions resulted in the impairment of certain gas and oil assets in 2008.

In the third quarter of 2008, Questar E&P sold certain outside-operated producing properties and leaseholds in the Gulf Coast region of south Texas and recognized a pre-tax gain of approximately $61.2 million. These properties contributed 2.8 Bcfe to Questar E&P net production in 2008. In 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.

Major Questar E&P Operating Areas

Pinedale Anticline

As of December 31, 2008, Market Resources (including both Questar E&P and Wexpro) operated and had working interests in 331 producing wells on the Pinedale Anticline compared to 250 at December 31, 2007. Of the 331 producing wells, Questar E&P has working interests in 309 wells, overriding royalty interests in an additional 21 Wexpro-operated wells, and no interest in one well operated by Wexpro. Wexpro has working interests in 107 of the 331 producing wells.

In 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10-acre-density drilling for Lance Pool wells on about 12,700 acres of Market Resources 17,872-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. At December 31, 2008, Questar E&P had booked 400 proved undeveloped locations on a combination of 5-, 10- and 20-acre density and reported estimated net proved reserves at Pinedale of 1,164.9 Bcfe, or 53% of Questar E&P total proved reserves. The Company continues to evaluate development on five-acre density at Pinedale. In January 2008, the WOGCC approved five-acre-density drilling for Lance Pool wells on about 4,200 gross acres of Market Resources Pinedale leasehold. If five-acre-density development is appropriate for a majority of its leasehold, the Company currently estimates up to 1,500 additional wells will be required to fully devel op the Lance Pool on its acreage.

Uinta Basin

As of December 31, 2008, Questar E&P had an operating interest in 909 gross producing wells in the Uinta Basin of eastern Utah, compared to 857 at December 31, 2007. At December 31, 2008, Questar E&P had booked 114 proved undeveloped locations and reported estimated net proved reserves in the Uinta Basin of 258.8 Bcfe or 12% of Questar E&P total proved reserves. Uinta Basin reserves declined 14% due to lower year-end 2008 gas and oil prices and a price-related slow down in development drilling. Uinta Basin proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs at depths of 5,000 feet to deeper than 18,000 feet. Questar E&P owns interests in over 252,000 gross leasehold acres in the Uinta Basin.

Rockies Legacy

The remainder of Questar E&P Rocky Mountain region leasehold interests, productive wells and proved reserves are distributed over a number of fields and properties managed as the company Rockies Legacy division. Most of the properties are located in the Greater Green River Basin of western Wyoming. In aggregate, Rockies Legacy properties comprised 163.6 Bcfe or 7% of Questar E&P total proved reserves at December 31, 2008. Exploration and development activity for 2008 includes wells in the San Juan, Paradox, Powder River, Green River, Vermillion and Williston Basins.

 

Midcontinent

Questar E&P Midcontinent properties are distributed over a large area, including the Anadarko Basin of Oklahoma and the Texas Panhandle, the Arkoma Basin of Oklahoma and western Arkansas, and the Ark-La-Tex region of Arkansas, Louisiana, and Texas. With the exception of northwest Louisiana, the Granite Wash play in the Texas Panhandle and the emerging Woodford Shale play in western Oklahoma, Questar E&P Midcontinent leasehold interests are fragmented, with no significant concentration of property interests. In aggregate, Midcontinent properties comprised 630.8 Bcfe or 28% of Questar E&P total proved reserves at December 31, 2008.

Questar E&P has approximately 31,000 net acres of Haynesville Shale lease rights in northwest Louisiana. The depth of the top of the Haynesville Shale ranges from approximately 10,500 feet to 12,500 feet across Questar E&P’s leasehold and is below the Hosston and Cotton Valley formations that Questar E&P has been developing in northwest Louisiana for over a decade. Questar E&P continues infill-development drilling in the Cotton Valley and Hosston formations in northwest Louisiana and intends to drill or participate in up to 35 horizontal Haynesville Shale wells in 2009. As of December 31, 2008, Questar E&P had 11 operated rigs drilling in the project area and operated or had working interests in 539 producing wells in northwest Louisiana compared to 463 at December 31, 2007.

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Wexpro

Wexpro reported net income of $73.9 million in 2008 compared to $59.2 million in 2007, a 25% increase and $50.0 million in 2006. Wexpro 2008 results benefited from a higher average investment base compared to the prior-year period. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19-20% on its investment base. Wexpro’s investment base is its investment in commercial wells and related facilities adjusted for working capital and reduced for deferred income taxes and depreciation. Wexpro’s investment base totaled $410.6 million at December 31, 2008, an increase of $110.2 million or 37% since December 31, 2007. Wexpro produced 46.1 Bcf of cost-of-service gas in 2008.

MIDSTREAM FIELD SERVICES – Questar Gas Management

Following is a summary of Gas Management financial and operating results:

	Year Ended December 31,				Change
	2008	2007	2006		2008 vs. 2007	2007 vs. 2006
	(in millions)
Operating Income
REVENUES
Gathering	$153.2	$111.4	$  89.2		$  41.8	$  22.2
Processing	137.0	94.9	94.7		42.1	0.2
Total Revenues	290.2	206.3	183.9		83.9	22.4
OPERATING EXPENSES
Operating and maintenance	95.0	83.6	92.4		11.4	(8.8)
General and administrative	23.7	17.2	12.2		6.5	5.0
Production and other taxes	2.6	1.4	0.6		1.2	0.8
Depreciation, depletion and amortization	28.7	19.1	15.3		9.6	3.8
Abandonment and impairments	0.8	0.4			0.4	0.4
Total Operating Expenses	150.8	121.7	120.5		29.1	1.2
Net gain from asset sales			1.0			(1.0)
Operating Income	$139.4	$  84.6	$  64.4		$  54.8	$  20.2
Operating Statistics
Natural gas gathering volumes (in millions of       MMBtu)
For unaffiliated customers	224.0	162.1		124.1	61.9	38.0
For affiliated customers	168.5	128.1		150.0	40.4	(21.9)
Total Gas Gathering Volumes	392.5	290.2		274.1	102.3	16.1
Gas gathering revenue (per MMBtu)	$0.31	$0.32		$0.29	($0.01)	$0.03
Natural gas processing volumes
NGL sales (MMgal)	89.5	76.5		88.1	13.0	(11.6)
NGL sales price (per gal)	$1.18	$0.98		$0.88	0.20	0.10
Fee-based processing volumes (in millions of       MMBtu)
For unaffiliated customers	87.4	44.1		37.5	43.3	6.6
For affiliated customers	114.1	82.5		82.9	31.6	(0.4)
Total Fee-Based Processing Volumes	201.5	126.6		120.4	74.9	6.2
Fee-based processing (per MMBtu)	$0.14	$0.15		$0.14	($0.01)	$0.01

Net income attributable to Gas Management grew 47% to $81.5 million in 2008 compared to $55.3 million in 2007 and $42.6 million in 2006. Net income growth was driven by higher gathering and processing margins.

Total gathering margins (revenues minus direct gathering expenses) in 2008 increased 74% to $116.9 million compared to $67.1 million in 2007. Expanding Pinedale production, new projects serving third parties in the Uinta Basin and the consolidation of

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Rendezvous contributed to a 38% increase in third-party volumes in 2008. Gathering volumes increased 102.3 million MMBtu, or 35% to 392.5 million MMBtu in 2008. Rendezvous, formerly an unconsolidated affiliate, was consolidated with Gas Management beginning in 2008 and accounted for 39.0 million MMBtu. Rendezvous provides gas gathering services for the Pinedale and Jonah producing areas of Wyoming.

Total processing margins (revenues minus direct plant expenses and processing plant-shrink) in 2008 increased 41% to $78.1 million compared to $55.4 million in 2007. Fee-based gas processing volumes were 201.5 million MMBtu in 2008, a 59% increase compared to 2007. In 2008, fee-based gas processing revenues increased 57% or $10.6 million, while the frac spread from keep-whole processing increased 28% or $12.4 million. Approximately 76% of Gas Management’s net operating revenue (revenue minus processing plant-shrink) in 2008 was derived from fee-based contracts, up from 74% in 2007.

Gas Management may use forward sales contracts to reduce margin volatility associated with keep-whole contracts. Forward sales contracts reduced NGL revenues by $1.4 million in 2008 and $5.9 million in 2007.

ENERGY MARKETING – Questar Energy Trading

Energy Trading net income was $22.1 million in 2008, an increase of 6% compared to 2007 net income of $20.8 million and 2006 net income of $9.6 million as a result of increased revenues from liquids produced from Clear Creek gas-storage facility and higher total marketing fees. Revenues from unaffiliated customers were $608.1 million in 2008 compared to $504.4 million in 2007, a 21% increase, primarily the result of higher natural gas prices. The weighted-average natural gas sales price increased 51% in 2008 to $6.34 per MMBtu, compared to $4.21 per MMBtu in 2007.

Consolidated Results below Operating Income

Interest and Other Income

Interest and other income increased $4.9 million or 51% in 2008 compared with 2007 $5.6 million or 137% in 2007 compared with 2006. In 2008, gains from inventory sales accounted for the majority of the increase, while the 2007 increase was the result of higher 2007 interest income and a $1.7 million loss from a 2006 early extinguishment of debt.

Income from unconsolidated affiliates

Income from unconsolidated affiliates was $1.7 million in 2008 compared to $8.9 million in 2007 and $7.5 million in 2006. Rendezvous Gas Services, which accounted for the majority of income from unconsolidated affiliates in 2007 and 2006, was consolidated beginning in 2008.

Net mark-to-market gain (loss) on basis-only 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 recognized a pre-tax net mark-to-market loss of $79.2 million on natural gas basis-only swaps in 2008 compared to a $5.7 million pre-tax gain in 2007 and a $1.9 million pre-tax loss in 2006.

Interest expense

Interest expense rose 75% in 2008 compared to 2007 due primarily to financing activities associated with the purchase of natural gas development properties in northwest Louisiana. Interest rates on the Questar’s commercial-paper borrowings spiked in September 2008 and later retreated reflecting increased liquidity pressures and turmoil generally experienced by financial markets. Questar maintains committed credit lines with banks to provide liquidity when commercial-paper markets are illiquid. Interest expense increased 5% in 2007 compared to 2006.

Income taxes

The effective combined federal and state income tax rate was 35.3% in 2008 compared with 36.4% in 2007 and 36.7% in 2006.

Investing Activities

Capital spending in 2008 amounted to $2,280.5 million. The details of capital expenditures in 2008 and 2007 and a forecast for 2009 are shown in the table below:

	Year Ended December 31,
	2009 Forecast	2008	2007
	(in millions)
Drilling and other exploration	$   790.1	$1,136.4	$678.7
Reserve acquisitions		727.8	46.1

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Wexpro development drilling	114.5	144.8	109.4
Midstream field services	149.1	394.5	128.1
Energy Trading and other	40.2	1.6	2.0
Capital expenditure accruals		(124.6)	(20.4)
Total	$1,093.9	$2,280.5	$943.9

Market Resources’ capital expenditures increased in 2008 compared to 2007 due to property acquisitions, an expanded drilling program and higher investments in gathering and processing facilities in the Rockies. In February 2008, Questar E&P acquired natural gas development properties in northwest Louisiana for an aggregate purchase price of $652.1 million. During 2008, Market Resources participated in 697 wells (267.2 net), resulting in 260.1 net successful gas and oil wells and 7.1 net dry or abandoned wells. The 2008 net drilling-success rate was 97.3%. There were 182 gross wells in progress at year-end.

Gas Management increased its investment in midstream gathering and processing-services business to expand capacity in both western Wyoming and eastern Utah in response to growing equity and third-party production volumes.

Standard & Poor’s Resolves Credit Ratings for Questar and its subsidiaries

On February 25, 2009, Standard & Poor’s affirmed both Questar’s commercial-paper rating of A2 and Market Resources’ BBB+ long-term debt rating, both with stable outlooks. This action followed Standard & Poor’s earlier announcement on October 15, 2008, that it had placed Questar and its subsidiaries on CreditWatch with negative implications and was initiating a review of Questar’s ratings. Standard & Poor’s review considered Questar’s increasing capital spending and the resulting higher proportion of operating income from gas and oil exploration and production activities, in addition to the volatility of gas and oil prices. Current ratings of senior-unsecured debt are as follows:

	Moody’s	Standard & Poor’s
Market Resources	Baa3	BBB+
Questar commercial paper	P2	A2

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, Market Resources enters into a variety of contractual cash obligations and other commitments. The following table summarizes the significant contractual cash obligations as of December 31, 2008:

	Payments Due by Year
	Total	2009	2010	2011	2012	2013	After 2013
	(in millions)
Fixed-rate long-term debt	$1,300.0			$150.0		$450.0	$700.0
Interest on fixed-rate long-term debt	423.4	$57.0	$57.0	47.6	$45.7	45.7	170.4
Drilling contracts	182.7	109.5	49.1	20.9	3.2
Transportation contracts	61.5	9.4	8.6	8.3	6.4	4.4	24.4
Operating leases	22.8	4.4	4.7	4.7	3.8	3.0	2.2
Total	$1,990.4	$180.3	$119.4	$231.5	$59.1	$503.1	$897.0

The Company had $450.0 million of variable-rate long-term debt outstanding due 2013 with an interest rate of 1.6% at December 31, 2008.

Critical Accounting Policies, Estimates and Assumptions

Gas and Oil Reserves

Gas and oil reserve estimates require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, production history, and economic assumptions relating to commodity prices, production costs, severance and other taxes, capital expenditures and remediation costs. The subjective judgments and variances in data for various fields make these estimates less precise than other estimates included in the financial statement disclosures. For 2008, revisions of reserve estimates, other than revisions related to Pinedale increased-density, resulted in a 152.9 Bcfe decrease in Questar E&P’s proved reserves and a 20.2 Bcfe decrease in cost-of-service proved reserves. Revisions associated with Pinedale increased-density drilling added 161.8 Bcfe to Questar E&P’s estimated prov ed reserves at December 31, 2008, and 68.2

7

Bcfe of additional cost-of-service proved reserves. See Note 15 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company’s estimated proved reserves.

Successful Efforts Accounting for Gas and Oil Operations

The Company follows the successful efforts method of accounting for gas- and oil-property acquisitions, exploration, development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs, the delay rental and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred.

The capitalized costs of unproved properties are generally combined and amortized over the expected holding period for such properties. Individually significant unproved properties are periodically reviewed for impairment. Capitalized costs of unproved properties are reclassified as proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.

Capitalized proved-property-acquisition costs are amortized by field using the unit-of-production method based on proved reserves. Capitalized exploratory-well and development costs are amortized similarly by field based on proved developed reserves. The calculation takes into consideration estimated future equipment dismantlement, surface restoration and property-abandonment costs, net of estimated equipment-salvage values. Other property and equipment are generally depreciated using the straight-line method over estimated useful lives or the unit-of-production method for certain processing plants. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production amortization rate would be significantly affected.

Questar E&P engages independent reservoir-engineering consultants to prepare estimates of the proved gas and oil reserves. Reserve estimates are based on a complex and highly interpretive process that is subject to continuous revision as additional production and development-drilling information becomes available.

Long-lived assets are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated on a field-by-field basis. Impairment is indicated when a triggering event occurs and the sum of estimated undiscounted future net cash flows of the evaluated asset is less than the asset’s carrying value. The asset value is written down to estimated fair value, which is determined using discounted future net cash flows.

Accounting for Derivative Contracts

The Company uses derivative contracts, typically fixed-price swaps, to hedge against a decline in the realized prices of its gas and oil production. Accounting rules for derivatives require marking these instruments to fair value at the balance-sheet reporting date. The change in fair value is reported either in net income or comprehensive income depending on the structure of the derivatives. The Company has structured virtually all energy-derivative instruments as cash-flow hedges as defined in SFAS 133 as amended. Changes in the fair value of cash-flow hedges are recorded on the balance sheet and in comprehensive income or loss until the underlying gas or oil is produced. When a derivative is terminated before its contract expires, the associated gain or loss is recognized in income over the life of the previously hedged production.

Revenue Recognition

Revenues are recognized in the period that services are provided or products are delivered. Questar E&P uses the sales method of accounting whereby revenue is recognized for all gas, oil and NGL sold to purchasers. Revenues include estimates for the two most recent months using published commodity-price indexes and volumes supplied by field operators. A liability is recorded to the extent that Questar E&P has an imbalance in excess of its share of remaining reserves in an underlying property. Energy Trading presents revenues on a gross-revenue basis. Energy Trading does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in prices.

Recent Accounting Developments

Refer to Note 1 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of recent accounting developments.

8

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Financial Statements:

Page No.

Report of Independent Registered Public Accounting Firm

10

Consolidated Statements of Income, three years ended December 31, 2008

11

Consolidated Balance Sheets at December 31, 2008 and 2007

12

Consolidated Statements of Changes in Equity, three years ended

December 31, 2008

14

Consolidated Statements of Cash Flows, three years ended December 31, 2008

15

Notes Accompanying Consolidated Financial Statements

17

Financial Statement Schedules:

For the three years ended December 31, 2008

    Valuation and Qualifying Accounts

37

All other schedules are omitted because they are not applicable or the required information

is shown in the Consolidated Financial Statements or Notes thereto.

9

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholder of

Questar Market Resources

We have audited the accompanying consolidated balance sheets of Questar Market Resources as of December 31, 2008 and 2007, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement pr esentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Questar Market Resources at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the financial statements, Questar Market Resources adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, effective January 1, 2007 and as discussed in Note 16, effective January 1, 2009, Questar Market Resources retrospectively adopted the presentation and disclosure requirements of FASB Statement No. 160 Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51.

/s/ Ernst & Young LLP

Salt Lake City, Utah

February 24, 2009, except for

Note 16 as to which the date is

May 29, 2009

10

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2008	2007	2006
	(in millions)
REVENUES
From unaffiliated customers	$2,297.2	$1,671.3	$1,659.4
From affiliated companies	232.9	172.1	176.4
Total Revenues	2,530.1	1,843.4	1,835.8
OPERATING EXPENSES
Cost of natural gas and other products sold (excluding operating     expenses shown separately)	575.1	474.7	652.6
Operating and maintenance	243.6	187.9	180.4
General and administrative	91.7	91.3	69.2
Production and other taxes	144.6	81.6	89.4
Depreciation, depletion and amortization	410.0	295.1	235.0
Exploration	29.3	22.0	34.4
Abandonment and impairment	45.4	11.2	7.6
Wexpro Agreement-oil income sharing	6.1	4.9	5.5
Total Operating Expenses	1,545.8	1,168.7	1,274.1
Net gain (loss) from asset sales	60.2	(1.3)	25.2
OPERATING INCOME	1,044.5	673.4	586.9
Interest and other income	14.6	9.7	4.1
Income from unconsolidated affiliates	1.7	8.9	7.5
Net mark-to-market gain (loss) on basis-only swaps	(79.2)	5.7	(1.9)
Interest expense	(62.2)	(35.6)	(33.9)
INCOME BEFORE INCOME TAXES	919.4	662.1	562.7
Income taxes	(324.9)	(241.3)	(206.6)
NET INCOME	594.5	420.8	356.1
Net income attributable to noncontrolling interest	(9.0)
NET INCOME ATTRIBUTABLE TO MARKET RESOURCES	$    585.5	$    420.8	$    356.1

See notes accompanying the consolidated financial statements

11

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2008	2007
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$   20.3
Notes receivable from Questar		$   103.2
Federal income taxes recoverable	11.1	4.6
Accounts receivable, net	265.2	246.1
Accounts receivable from affiliates	28.1	18.3
Fair value of derivative contracts	431.3	78.1
Inventories, at lower of average cost or market
Gas and oil storage	23.6	23.2
Materials and supplies	86.8	33.2
Prepaid expenses and other	28.0	18.2
Total Current Assets	894.4	524.9
Property, Plant and Equipment – successful efforts     method of accounting for gas and oil properties
Questar E&P
Proved properties	4,912.6	3,306.9
Unproved properties, not being depleted	193.2	55.6
Support equipment and facilities	35.6	23.3
Wexpro	911.5	766.1
Gas Management	976.6	516.5
Energy Trading and other	41.3	39.9
	7,070.8	4,708.3
Less accumulated depreciation, depletion and amortization
Questar E&P	1,421.8	1,114.3
Wexpro	374.9	331.4
Gas Management	159.3	115.3
Energy Trading and other	8.4	6.7
	1,964.4	1,567.7
Net Property, Plant and Equipment	5,106.4	3,140.6
Investment in unconsolidated affiliates	40.8	52.8
Other Assets
Goodwill	60.2	60.9
Contract receivable from Questar Gas	3.6	3.9
Fair value of derivative contracts	106.3	7.8
Other noncurrent assets	22.7	15.5
Total Other Assets	192.8	88.1
Total Assets	$6,234.4	$3,806.4

12

LIABILITIES AND EQUITY

	December 31,
	2008	2007
	(in millions)
Current Liabilities
Notes payable to Questar	$  89.4	$  118.9
Accounts payable and accrued expenses
Accounts and other payables	411.7	303.7
Accounts payable to affiliates	14.1	13.0
Production and other taxes	46.2	40.9
Interest	19.5	9.3
Total accounts payable and accrued expenses	491.5	366.9
Fair value of derivative contracts	0.5	9.3
Deferred income taxes – current	138.1	13.3
Total Current Liabilities	719.5	508.4
Long-term debt	1,299.1	499.3
Deferred income taxes	1,138.3	731.4
Asset retirement obligations	171.2	145.3
Fair value of derivative contracts	69.0	22.1
Other long-term liabilities	57.9	39.8
Commitments and Contingencies – Note 9
EQUITY
Common stock – par value $1 per share;
25.0 shares authorized; 4.3 shares issued and outstanding	4.3	4.3
Additional paid-in capital	141.9	130.9
Retained earnings	2,262.1	1,693.9
Accumulated other comprehensive income	341.6	31.0
Total Common Shareholder’s Equity	2,749.9	1,860.1
Noncontrolling interest	29.5
Total Equity	2,779.4	1,860.1
Total Liabilities and Equity	$6,234.4	$3,806.4

See notes accompanying the consolidated financial statements

13

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

				Accumulated		Comp-
		Additional		Other	Non-	rehensive
	Common	Paid-in	Retained	Comprehensive	controlling	Income
	Stock	Capital	Earnings	Income (Loss)	Interest	(Loss)
		(in millions)
Balance at January 1, 2006	$4.3	$116.0	$951.6	($198.1)
2006 net income			356.1			$356.1
Dividends paid			(17.3)
Share-based compensation		6.0
Other comprehensive income
Change in unrealized fair value of derivatives				524.9		524.9
Income taxes				(198.7)		(198.7)
Total comprehensive income						$682.3
Balance at December 31, 2006	4.3	122.0	1,290.4	128.1
2007 net income			420.8			$420.8
Dividends paid			(17.3)
Share-based compensation		8.9
Other comprehensive income
Change in unrealized fair value of derivatives				(156.1)		(156.1)
Income taxes				59.0		59.0
Total comprehensive income						$323.7
Balance at December 31, 2007	4.3	130.9	1,693.9	31.0
Consolidation of Rendezvous Gas Services					$29.8
2008 net income			585.5		9.0	$594.5
Dividends paid			(17.3)
Distribution to noncontrolling interest					(9.3)
Share-based compensation		11.0
Other comprehensive income
Change in unrealized fair value of derivatives				494.0		494.0
Income taxes				(183.4)		(183.4)
Total comprehensive income						$905.1
Balance at December 31, 2008	$4.3	$141.9	$2,262.1	$341.6	$29.5

See notes accompanying the consolidated financial statements

14

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2008	2007	2006
	(in millions)
OPERATING ACTIVITIES
Net income	$594.5	$420.8	$356.1
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	411.5	296.0	236.8
Deferred income taxes	335.3	183.0	110.7
Abandonment and impairment	45.4	11.2	7.6
Share-based compensation	11.0	8.9	6.0
Dry exploratory well expenses	9.7	12.3	26.3
Net (gain) loss from asset sales	(60.2)	1.3	(25.2)
Income from unconsolidated affiliates	(1.7)	(8.9)	(7.5)
Distribution from unconsolidated affiliates	0.5	10.4	7.1
Net mark-to-market (gain) loss on basis-only swaps	79.2	(5.7)	1.9
Other	1.0	(1.0)	1.8
Changes in operating assets and liabilities:
Accounts receivable	(28.9)	(6.7)	32.7
Inventories	(54.0)	5.8	0.7
Prepaid expenses	(9.8)	4.3	0.9
Accounts payable and accrued expenses	14.4	(34.0)	(28.0)
Federal income taxes	(6.5)	(3.2)	12.7
Other	12.7	1.0	(12.2)
NET CASH PROVIDED FROM OPERATING ACTIVITIES	1,354.1	895.5	728.4
INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(2,249.3)	(916.8)	(720.1)
Dry exploratory well expenses	(9.7)	(12.3)	(26.3)
Other investments	(21.5)	(14.8)	(6.3)
Total capital expenditures	(2,280.5)	(943.9)	(752.7)
Proceeds from disposition of assets	103.4	4.6	31.3
Affiliated-company property, plant and equipment transfers			(2.3)
NET CASH USED IN INVESTING ACTIVITIES	(2,177.1)	(939.3)	(723.7)
FINANCING ACTIVITIES
Change in notes receivable from Questar	103.2	(33.4)	19.3
Change in notes payable to Questar	(29.5)	(23.7)	(38.2)
Long-term debt issued, net of issue costs	1,395.2	100.0	247.0
Long-term debt repaid	(600.0)		(200.0)
Distribution to noncontrolling interest	(9.3)
Dividends paid	(17.3)	(17.3)	(17.3)
Other	1.0		(1.7)

15

NET CASH PROVIDED FROM FINANCING ACTIVITIES	843.3	25.6	9.1
Change in cash and cash equivalents	20.3	(18.2)	13.8
Beginning cash and cash equivalents		18.2	4.4
Ending cash and cash equivalents	$  20.3	$	$   18.2
Supplemental Disclosure of Cash Paid During the Year for:
Interest	$55.9	$34.5	$31.9
Income taxes	2.5	64.9	81.1

See notes accompanying the consolidated financial statements

16

QUESTAR MARKET RESOURCES, INC.

NOTES ACCOMPANYING CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies

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 subholding company with three major lines of business – gas and oil exploration and production, midstream field services, and energy marketing – which are conducted through its 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.

Principles of Consolidation

The consolidated financial statements contain the accounts of Market Resources 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 annual reports on Form 10-K and Regulations S-X and S-K. Rendezvous Gas Services, an affiliate, was consolidated beginning in 2008 as a result of a step acquisition caused by disproportionate ownership. All significant intercompany accounts and transactions have been eliminated in consolidation.

Investment in Unconsolidated Affiliates

Market Resources 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 would be included in the determination of net income.

The principal unconsolidated affiliates and Market Resources’ ownership percentage as of December 31, 2008, were Uintah Basin Field Services, LLC, a limited liability corporation (38%) and Three Rivers Gathering, a limited liability corporation (50%). These entities are engaged in gathering and compressing natural gas.

Use of Estimates

The preparation of consolidated financial statements and notes in conformity with GAAP requires management to formulate estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.

Revenue Recognition

Market Resources subsidiaries recognize revenues in the period that services are provided or products are delivered. Revenues reflect the impact of price-hedging instruments. Revenues associated with the production of gas and oil are accounted for using the sales method, whereby revenue is recognized as gas and oil is sold to purchasers. A liability is recorded to the extent that the company has sold volumes in excess of its share of remaining gas and oil reserves in an underlying property. Market Resources imbalance obligations at December 31, was $3.1 million in 2008 and $2.7 million in 2007.

Energy Trading reports revenues on a gross basis because, in the judgment of management, the nature and circumstances of its marketing transactions are consistent with guidance for gross revenue reporting. Market Resources is primarily engaged in gas and oil exploration and production and midstream field services. Energy Trading markets equity natural gas, oil and NGL and third-party volumes. Energy Trading uses derivatives to secure a known price for a specific volume over a specific time period. Energy Trading does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. Energy Trading has not engaged in buy/sell arrangements, as described in EITF 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty.”

17

Wexpro Agreement – Oil Income Sharing

Oil income sharing represents payments made to Questar Gas for its share of the income from oil and NGL products associated with cost-of-service properties pursuant to the Wexpro Agreement. See Note 12 for more information on the Wexpro Agreement.

Regulation of Underground Storage

Market Resources through Clear Creek Storage Company, LLC, operates a gas-storage facility under the jurisdiction of the Federal Energy Regulatory Commission (FERC). The FERC establishes rates for the storage of natural gas. The FERC also regulates, among other things, the extension and enlargement or abandonment of jurisdictional natural gas facilities. Regulation is intended to permit the recovery, through rates, of the cost of service, including a return on investment.

Cash and Cash Equivalents

Cash equivalents consist principally of repurchase agreements with maturities of three months or less. In almost all cases, the repurchase agreements are highly liquid investments in overnight securities made through commercial-bank accounts that result in available funds the next business day.

Notes Receivable from Questar

Notes receivable from Questar represent interest bearing demand notes for cash loaned to Questar until needed in the Company’s operations. The funds are centrally managed by Questar and earn an interest rate that is identical to the interest rate paid by the Company for borrowings from Questar.

Property, Plant and Equipment

Property, plant and equipment balances are stated at historical cost. Maintenance and repair costs are expensed as incurred.

Gas and oil properties

Questar E&P uses the successful efforts method to account for gas and oil properties. The costs of acquiring leaseholds, drilling development wells, drilling successful exploratory wells, purchasing related support equipment and facilities are capitalized and depreciated on a field basis using the unit-of-production method and the estimated proved developed gas and oil reserves. Costs of geological and geophysical studies and other exploratory activities are expensed as incurred. Costs of production and general corporate activities are expensed in the period incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected.

Capitalized costs of unproved properties are generally combined and amortized over the expected holding period for such properties. Capitalized costs of unproved properties are reclassified as proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.

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.

Cost-of-service gas and oil operations

The successful efforts method of accounting is used for “cost-of-service” reserves, managed, developed and produced by Wexpro for gas utility affiliate Questar Gas. Cost-of-service reserves are properties for which the operations and return on investment are subject to the Wexpro Agreement (see Note 12). In accordance with the agreement, production from the gas properties operated by Wexpro is delivered to Questar Gas at Wexpro’s cost of providing this service including a return on Wexpro’s investment. Wexpro sells crude-oil production from certain oil-producing properties at market prices with the revenues used to recover operating expenses and to provide Wexpro a return on its investment. Any operating income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%. Amounts received by Questar Gas from the sharing of Wexpro’s oil income are used to reduce natural-gas costs to utility customers.

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-

18

production method. The following rates per Mcfe represent the volume-weighted average depreciation, depletion and amortization rates of the Company’s capitalized costs:

	2008	2007	2006
Gas and oil properties, per Mcfe	$1.93	$1.74	$1.43
Cost-of-service gas and oil properties, per Mcfe	1.27	1.09	$1.04

Depreciation, depletion and amortization for the remaining Company properties is based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets using either a straight-line or unit-of-production method. Investment in gas-gathering and processing fixed assets is charged to expense using either the straight-line or unit-of-production method depending upon the facility.

Impairment of Long-Lived Assets

Proved gas and oil properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset’s carrying value. Triggering events could include, but are not limited to, an impairment of gas and oil reserves caused by mechanical problems, faster-than-expected decline of reserves, lease-ownership issues, other-than-temporary decline in gas and oil prices and changes in the utilization of pipeline assets. If impairment is indicated, fair value is calculated using a discounted-cash-flow approach. Cash-flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices and operating costs.

The Company also performs periodic assessments of individually significant unproved gas and oil properties for impairment and recognizes a loss at the time of impairment. In determining whether a significant unproved property is impaired the Company considers numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists’ evaluations of the lease, and the remaining lease term.

Goodwill and Other Intangible Assets

Goodwill represents the excess of the amount paid by Questar E&P over the fair value of net assets acquired in a business combination and is not subject to amortization. Goodwill and indefinite lived intangible assets are tested for impairment at a minimum of once a year or when a triggering event occurs. If a triggering event occurs, the undiscounted net cash flows of the intangible asset or entity to which the goodwill relates are evaluated. Impairment is indicated if undiscounted cash flows are less than the carrying value of the assets. The amount of the impairment is measured using a discounted-cash-flow model considering future revenues, operating costs, a risk-adjusted discount rate and other factors.

Capitalized Interest and Allowance for Funds Used During Construction (AFUDC)

The Company capitalizes interest costs when applicable. Interest expense was reduced by $4.9 million in 2008. The Wexpro Agreement requires capitalization of AFUDC on cost-of-service construction projects. AFUDC on equity funds amounted to $3.1 million in 2008, $1.3 million in 2007 and $0.9 million in 2006 and increased interest and other income in the Consolidated Statements of Income.

Derivative Instruments

The Company may elect to designate a derivative instrument as a hedge of exposure to changes in fair value or cash flows. If the hedged exposure is a fair-value exposure, the gain or loss on the derivative instrument is recognized in earnings in the period of the change together with the offsetting gain or loss from the change in fair value of the hedged item. If the hedged exposure is a cash-flow exposure, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any amount excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the gain or loss, is reported in the current period income statement. A derivative instrument qualifies as a cash-flow hedge if all of the following tests are met:

·

The item to be hedged exposes the Company to price risk.

·

The derivative reduces the risk exposure and is designated as a hedge at the time the Company enters into the contract.

·

At the inception of the hedge and throughout the hedge period, there is a high correlation between changes in the market value of the derivative instrument and the fair value of the underlying hedged item.

When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are included in income in the same period that the underlying production or other contractual commitment is delivered. When a derivative instrument is associated with an anticipated transaction that is no longer probable, the gain or loss on the

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derivative is reclassified from other comprehensive income and recognized currently in the results of operations. When a derivative is terminated before its contract expires, the associated gain or loss is recognized in income over the life of the previously hedged production.

Basis-Only Swaps

Basis-only swaps are used to manage the risk of widening basis differentials. These contracts are marked to market monthly with any change in the valuation recognized in the determination of net income.

Physical Contracts

Physical-hedge contracts have a nominal quantity and a fixed price. Contracts representing both purchases and sales settle monthly based on quantities valued at a fixed price. Purchase contracts fix the purchase price paid and are recorded as cost of sales in the month the contracts are settled. Sales contracts fix the sales price received and are recorded as revenues in the month they are settled. Due to the nature of the physical market, there is a one-month delay for the cash settlement. Market Resources accrues for the settlement of contracts in the current month’s revenues and cost of sales.

Financial Contracts

Financial contracts are contracts that are net settled in cash without delivery of product. Financial contracts also have a nominal quantity and exchange an index price for a fixed price, and are net settled with the brokers as the price bulletins become available. Financial contracts are recorded in cost of sales in the month of settlement.

Credit Risk

The Rocky Mountain and Midcontinent regions constitute the Company’s primary market areas. Exposure to credit risk may be affected by the concentration of customers in these regions due to changes in economic or other conditions. Customers include individuals and numerous commercial and industrial enterprises that may react differently to changing conditions. Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses. Commodity-based hedging arrangements also expose the Company to credit risk. The Company monitors the creditworthiness of its counterparties, which generally are major financial institutions and energy companies. Loss reserves are periodically reviewed for adequacy and may be established on a specific case basis. Market Resources requests credit support and, in some cases, fungible collateral from companies with unacceptable credit risks. The C ompany has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

Bad debt expense amounted to $0.4 million in 2008, $0.1 million in 2007 and $1.4 million in 2006. The allowance for bad debt expenses was $2.7 million at December 31, 2008, and $3.3 million at December 31, 2007.

Income Taxes

Questar and its subsidiaries file a consolidated federal income tax return. Market Resources accounts for income tax expense on a separate-return basis and records tax benefits as they are generated. The Company receives payments from Questar for such tax benefits as they are utilized on the consolidated income tax return. Deferred income taxes have been provided for temporary differences caused by differences between the book and tax-carrying amounts of assets and liabilities. These differences create taxable or tax deductible amounts for future periods. Interest earned on refunds is recorded in interest and other income. Interest expense charged on tax deficiencies is recorded in interest expense.

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 Statement of Financial Accounting Standards (SFAS) 109 “Accounting for Income Taxes.” FIN 48 provides guidance for 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. Questar adopted the provisions of FIN 48 effective January 1, 2007. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company’s recorded income tax benefits will be fully realized. There were no unrecognized tax benefits at the beginning or at the end of the twelve-month periods ended December 31, 2008 and 2007. Income tax returns for 2005 and subsequent years are subject to examination. As of the date of adoption, there were no amounts accrued for penalties or interest related to unrecognized tax benefits.

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). 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

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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 measured at the grant-date market price.

The Company implemented SFAS 123R “Share Based Payment,” effective January 1, 2006, and chose the modified prospective phase-in method. The modified prospective phase-in method requires recognition of compensation costs for all share-based payments granted, modified or settled after January 1, 2006, as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. Questar uses an accelerated method in recognizing share-based compensation costs with graded-vesting periods. See Note 2 for further discussion on share-based compensation.

Comprehensive Income

Comprehensive income is the sum of net income as reported in the Consolidated Statement of Income and other comprehensive income transactions reported in the Consolidated Statement of Common Shareholder’s Equity. Other comprehensive income or loss is the result of changes in the market value of gas and oil cash-flow derivatives. These transactions are not the culmination of the earnings process, but result from periodically adjusting historical balances to fair value. Income or loss is realized when the underlying energy product is sold.

Business Segments

Line of business information is presented according to senior management’s basis for evaluating performance considering differences in the nature of products, services and regulation. Certain intersegment sales include intercompany profit.

Recent Accounting Developments

SFAS 141(R) “Business Combinations”

SFAS 141(R) requires the acquiring entity in a business combination to recognize the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) is effective beginning January 1, 2009 and will be applied to business combinations occurring after the effective date.

SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities”

This statement, issued by the FASB in March 2008, requires more detailed information on hedging transactions including the location and effect on the primary financial statements. The addition disclosure is required for interim and annual periods beginning after November 15, 2008. SFAS 161 does not change the accounting for derivative instruments and hedging activities. The Company will supply the new disclosure information as required by SFAS 161 beginning in 2009 and does not expect the new rules to impact the Company’s financial position or results of operations.

SEC “Modernization of Oil and Gas Reporting Requirements”

In December 2008, the SEC issued a final rule on its revised oil and gas reserve estimation and reporting requirements. The new rule expands the definition of oil and gas reserves to include, among other things, non-traditional sources, optional disclosure of probable and possible reserves and economic producibility based on modified pricing assuming a 12-month average when estimating reserves. The new rule is effective for annual reports on Form 10-K filed for years ending December 31, 2009, and early adoption is not permitted. The SEC is coordinating with the FASB to obtain the revisions necessary to SFAS 19, “Financial Reporting and Reporting by Oil and Gas Producing Companies”, and SFAS 69, “Disclosures about Oil and Gas Producing Activities” to provide consistency with the new rule. In the event that consistency is not achieved in time for companies to comply with the new rule, the SEC will consider delaying the compliance date. The Company is evaluating the eff ect of the SEC’s rule changes on future oil and gas disclosures, income, cash flow and the balance sheet.

Reclassifications

Certain reclassifications were made to prior-year consolidated financial statements to conform with the 2008 presentation.

All dollar and share amounts in this annual report on Form 10-K are in millions, except per-share information and where otherwise noted.

Note 2 – Share-Based Compensation

Questar issues stock options and restricted shares to certain officers and employees of Market Resources under its LTSIP and recognizes expense over time as the stock options or restricted shares vest. The Company uses an accelerated method in

21

recognizing share-based compensation costs with graded-vesting periods. Share-based compensation expense amounted to $11.0 million in 2008 compared with $8.9 million in 2007 and $6.0 million in 2006.

The Company uses the Black-Scholes-Merton mathematical model in estimating the fair value of stock options for accounting purposes. Fair-value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model was intended for measuring the value of options traded on an exchange. The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:

		October 2008	February 2007
Fair value of options at grant date		$28.58	$41.08
Risk-free interest rate		3.20%	4.77%
Expected price volatility		32.3%	22.4%
Expected dividend yield		1.72%	1.14%
Expected life in years		5.0	5.2

Unvested stock options increased by 287,500 shares to 547,500 in 2008. Stock-option transactions under the terms of the LTSIP for the three years ended December 31, 2008, are summarized below:

	Options Outstanding	Price Range	Weighted- Average Price
Balance at January 1, 2006	1,802,638	$7.50 – $38.57	$15.09
Exercised	(364,496)	7.50 –   17.55	11.57
Balance a December 31, 2006	1,438,142	7.50 –  38.57	15.97
Granted	60,000	41.08	41.08
Exercised	(157,464)	7.50 –  17.55	12.71
Employee transferred	(16,064)	10.69	10.69
Forfeited	(1,000)	14.01	14.01
Balance at December 31, 2007	1,323,614	7.50 – 41.08	17.57
Granted	287,500	28.58	28.58
Exercised	(82,454)	7.50 – 17.55	11.44
Employee transferred	(58,210)	7.50 – 14.01	12.39
Balance at December 31, 2008	1,470,450	$7.50 – $28.58	$20.16

	Options Outstanding			Options Exercisable		Nonvested Options
Range of exercise prices	Number outstanding at Dec. 31, 2008	Weighted-average remaining term in years	Weighted-average exercise price	Number exercisable at Dec. 31, 2008	Weighted-average exercise price	Number nonvested at Dec. 31, 2008	Weighted-average exercise price
$  7.50 - $  8.50	119,116	0.9	$   7.81	119,116	$   7.81
11.48 -    11.98	366,842	3.1	11.71	366,842	11.71
13.56  -   17.55	436,992	3.8	13.78	436,992	13.78
$28.58 - $41.08	547,500	3.5	33.60			547,500	$33.60
	1,470,450	3.3	$20.16	922,950	$12.19	547,500	$33.60

Restricted shares are valued at the grant-date market price and amortized to expense over the vesting period. Most restricted share grants vest in equal installments over a three or four year period from the grant date. The weighted average vesting period of unvested restricted shares at December 31, 2008, was 16 months. Transactions involving restricted shares under the terms of the LTSIP for the three years ended December 31, 2008, are summarized below:

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	Restricted Shares Outstanding	Price Range	Weighted-Average Price
Balance at January 1, 2006	354,482	$13.56 - $43.02	$20.64
Granted	231,580	35.20 -  44.77	37.10
Distributed	(121,326)	13.56 -   43.02	17.85
Forfeited	(4,990)	14.36 -   38.00	31.14
Balance at December 31, 2006	459,746	14.36 –   44.77	29.54
Granted	290,740	38.96 –   55.42	46.02
Distributed	(160,606)	14.36 –   49.98	23.40
Forfeited	(26,702)	18.45 –   49.97	35.22
Balance at December 31, 2007	563,178	14.36 –   55.42	39.40
Granted	239,490	25.12 –   70.13	53.95
Distributed	(175,209)	17.45 –   56.65	34.36
Employee transferred	(866)	17.45 –   36.75	26.92
Forfeited	(26,916)	25.50 –   70.13	47.30
Balance at December 31, 2008	599,677	$14.36 – $70.13	$46.35

Note 3 – Questar E&P Property Acquisitions and Divestitures

In February 2008, Questar E&P acquired natural gas development properties in northwest Louisiana for an aggregate purchase price of $652.1 million effective January 1, 2008. The acquisition was accounted for as a purchase and, accordingly, the results of operations of the properties were included in net income from the closing date of the acquisition. After recording deferred income taxes of $13.1 million, the purchase price allocated to proved properties was $570.9 million and to unproved properties was $81.2 million. The transaction was initially funded with short-term bank debt.

In conjunction with the acquisition of the Louisiana properties, the Company identified certain outside-operated producing properties and leaseholds in the Gulf Coast region of south Texas for divestiture. These properties contributed 2.8 Bcfe to Questar E&P net production in 2008. For income tax purposes, the Company structured a portion of the purchase of the Louisiana properties and the July 31, 2008, sale of the south Texas properties as a reverse like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended. The Company recognized a pre-tax gain on the sale of the Texas properties of approximately $61.2 million.

Questar E&P abandonment and impairment expense increased $33.8 million or 313% in 2008 compared to 2007. Abandonment and impairment expense increased $29.9 million in the fourth quarter of 2008 compared with the same period of 2007. Lower year-end 2008 gas and oil prices triggered impairment testing of long-lived assets. Future cash flows using estimated forward-looking commodity prices were sufficient to recover the investment of a majority of the long-lived assets. A combination of poor production performance, higher production costs and negative reserve revisions resulted in the impairment of certain gas and oil assets in 2008.

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. 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 ARO were as follows:

	2008	2007
	(in millions)
ARO liability at January 1,	$145.3	$128.3
Accretion	9.4	8.1
Liabilities incurred	17.2	8.9
Revisions	1.5	1.5

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Liabilities settled	(2.2)	(1.5)
ARO liability at December 31,	$171.2	$145.3

Wexpro activities are governed by 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 funds related to estimated ARO costs. The funds are used to satisfy retirement obligations as the properties are abandoned. At December 31, 2008, approximately $9.9 million was held in this trust invested primarily in a short-term bond index fund.

Note 5 – Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs are presented in the table below and exclude amounts that were capitalized and subsequently expensed in the period. All of these costs have been capitalized for less than one year.

	2008	2007	2006
	(in millions)
Balance at January 1,	$ 1.5	$ 10.5	$  16.5
Additions to capitalized exploratory well costs pending the
determination of proved reserves	17.0	1.5	10.5
Reclassifications to property, plant and equipment after the
determination of proved reserves			(5.0)
Capitalized exploratory well costs charged to expense	(1.5)	(10.5)	(11.5)
Balance at December 31,	$17.0	$   1.5	$  10.5

Note 6 – Fair-Value Measures, Financial Instruments and Risk Management

Beginning in 2008, Market Resources adopted the effective provisions of SFAS 157 “Fair-Value Measures.” SFAS 157 defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair-value measurements. SFAS 157 does not change existing guidance as to whether or not an instrument is carried at fair value. Also, the new standard establishes a fair-value hierarchy. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. In February 2008, the FASB issued FASB Staff Position Financial Accounting Standard 157-2 “Partial Deferral of the Effective Date of Statement 157,” which delays the effective date for nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis. For Market Resources, the delayed provisions of SFAS 157 go into effect in the first quarter of 2009. The adoption of SFAS 157 did not have a significant effect on the Company’s financial position or results of operations.

The following table discloses carrying value and fair value of financial instruments:

	Carrying	Estimated	Carrying	Estimated
	Value	Fair Value	Value	Fair Value
	December 31, 2008		December 31, 2007
	(in millions)
Financial assets
Cash and cash equivalents	$    20.3	$    20.3
Notes receivable from Questar			$103.2	$103.2
Fair value of derivative contracts – short-term	431.3	431.3	78.1	78.1
Fair value of derivative contracts – short-term	106.3	106.3	7.8	7.8
Financial liabilities
Notes payable to Questar	89.4	89.4	118.9	118.9

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Fair value of derivative contracts – short-term	0.5	0.5	9.3	9.3
Long-term debt	1,300.0	1,180.9	500.0	503.1
Fair value of derivative contracts – long-term	69.0	69.0	22.1	22.1

Cash and cash equivalents and short-term debt – the carrying amount approximates fair value.

Long-term debt – the carrying amount of variable-rate debt approximates fair value. The fair value of fixed-rate debt is based on the discounted present value of cash flows using the Company’s current borrowing rates.

Derivative contracts – the Company enters into commodity-price derivative arrangements that do not require collateral deposits. The fair value of these derivative contracts is based on market prices posted on the NYMEX and considered Level 2 under the provisions of SFAS 157. At December 31, 2008, counterparties under the derivative contracts were banks and energy-trading firms with investment-grade credit ratings. Gas derivatives are structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. As of December 31, 2008, Market Resources held gas-price-derivative instruments covering the price exposure for about 234.4 million MMBtu of natural gas, 0.7 million barrels of oil and basis-only swaps on an additional 204.9 Bcf of natural gas. About $430.8 million of the fair value of all contracts as of December 31, 2008, will settle and be reclassified from other comprehensive income in the next 12 months. A year earlier Market Resources derivatives covered the price exposure for 245.0 million MMBtu of natural gas, 2.0 million barrels of oil, 5.0 million gallons of NGL and basis-only swaps on an additional 40.8 Bcf of natural gas.

At December 31, 2008, the Company reported the fair value of fixed-price derivative assets, net of liabilities, of $543.6 million. The offset to the net derivative assets, net of income taxes, was a $341.6 million unrealized gain on derivatives recorded in accumulated other comprehensive income in the Common Shareholders’ Equity section of the Consolidated Balance Sheets. During 2008, $21.7 million of fair value associated with fixed-price derivatives settled and was reclassified into income. The ineffective portion of derivative transactions recognized in earnings was $1.0 million loss in 2008. The fair-value calculation of gas- and oil-price derivatives does not consider changes in the fair value of the corresponding scheduled equity physical transactions, (i.e., the correlation between index price and the price realized for the physical delivery of gas or oil).

Note 7 – Debt

Questar makes loans to Market Resources under a short-term borrowing arrangement. Short-term notes payable to Questar are subordinated to obligations under the revolving credit agreement. Short-term notes payable to Questar amounted to $89.4 million with an interest rate of 3.39% December 31, 2008, and $118.9 million with an interest rate of 5.36% at December 31, 2007.

All long-term notes and the term-bank loan are unsecured obligations and rank equally with all other unsecured liabilities. Market Resources’ revolving-credit facility had $450.0 million outstanding and a weighted-average interest rate of 1.60% at December 31, 2008. This credit agreement carries an annual commitment fee of 0.115% of the unused balance. At December 31, 2008, Market Resources could pay dividends of $891.0 million without violating the terms of its debt covenants.

In March 2008, Market Resources filed a shelf registration with the SEC to sell up to $700.0 million of debt securities and to use the net proceeds to repay bank borrowings and to finance certain capital expenditures as well as for general corporate purposes, including working capital. In April 2008, Market Resources sold $450.0 million of 10-year notes with a 6.8% interest rate. In March 2008, Market Resources also entered into a new $800.0 million five-year revolving-credit facility. The net proceeds from the sale of the notes and funds borrowed under the revolving-credit facility were used to reduce short-term bank debt described in Note 3. In an October 2008 filing with the SEC, Market Resources increased the unused portion of its March 2008 shelf registration from $250.0 million to $300.0 million.

The details of long-term debt are as follows:

	December 31,
	2008	2007
	(in millions)
Revolving-credit facility, 1.60% at December 31, 2008, due 2013	$   450.0
Revolving term loan, 5.55% at December 31, 2007, due 2012		$   100.0
7.50% notes due 2011	150.0	150.0
6.05% notes due 2016	250.0	250.0

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6.80% notes due 2018	450.0
Total long-term debt outstanding	1,300.0	500.0
Less unamortized-debt discount	(0.9)	(0.7)
Total long-term debt outstanding	$1,299.1	$499.3

The Company’s 7.5% notes and revolving term facility are scheduled to be repaid within five years following December 31, 2008.

Note 8 – Income Taxes

Details of Market Resources income tax expense and deferred income taxes are provided in the following tables. The components of income tax expense were as follows:

	Year Ended December 31,
	2008	2007	2006
	(in millions)
Federal
Current	($  7.6)	$  56.4	$  89.3
Deferred	322.9	166.1	98.5
State
Current	(2.8)	1.9	6.6
Deferred	12.4	16.9	12.2
	$324.9	$241.3	$206.6

The difference between the statutory federal income tax rate and the Company’s effective income tax rate is explained as follows:

	Year Ended December 31,
	2008	2007	2006
Federal income tax statutory rate	35.0%	35.0%	35.0%
State income taxes, net of federal income tax benefit	0.7	1.8	2.2
Domestic production benefit		(0.3)	(0.4)
Other	(0.4)	(0.1)	(0.1)
Effective income tax rate	35.3%	36.4%	36.7%

Significant components of the Company’s deferred income taxes were as follows:

	December 31,
	2008	2007
	(in millions)
Deferred tax liabilities
Property, plant and equipment	$1,132.3	$744.7
Energy-price derivatives	13.6
Total deferred tax liabilities	1,145.9	744.7
Deferred tax assets
Energy-price derivatives		6.0
Employee benefits and compensation costs	7.6	7.3
Total deferred tax assets	7.6	13.3
Net deferred income taxes	$1,138.3	$731.4

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Deferred income taxes – current liability
Energy-price derivatives	$160.4	$ 26.2
Other	(22.3)	(12.9)
Deferred income taxes – current liability	$138.1	$ 13.3

Note 9 – Commitments and Contingencies

Market Resources 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 the Company’s financial position, results of operations or cash flows. A liability is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. Disclosures are provided for contingencies reasonably likely to occur which would have a material-adverse effect on the Company’s financial position, results of operations or cash flows. 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.

Environmental Claims

In United States of America v. Questar Gas Management Co., filed on February 29, 2008, in Utah Federal District Court, the Environmental Protection Agency (EPA) alleges that Gas Management violated the federal Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. EPA further alleges that the facilities are located within the original boundaries of the former Uncompahgre Indian Reservation and asserts primary CAA jurisdiction. Gas Management intends to vigorously defend against the EPA’s claims, and believes that the major source permitting and regulatory requirements at issue can be legally resolved. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict the likely potential outcomes; however, management believes the company has accrued an appropriate liability for this claim.

Commitments

Subsidiaries of Market Resources have contracted for firm-transportation services with various third-party pipelines through 2028. Market conditions and competition may prevent full recovery of the cost. Annual payments and the years covered are as follows:

	(in millions)
2009	$ 9.4
2010	8.6
2011	8.3
2012	6.4
2013	4.4
2014 through 2028	24.4

Market Resources rents office space throughout its scope of operations from third-party lessors and leases space in an office building located in Salt Lake City, Utah from an affiliated company that expires January 12, 2012. Rental expense amounted to $4.0 million in 2008, $3.0 million in 2007 and $2.5 million in 2006. The minimum future payments under the terms of long-term operating leases for the Company’s primary office locations for the six years following December 31, 2008, are as follows:

	(in millions)
2009	$4.4
2010	4.7
2011	4.7
2012	3.8
2013	3.0
2014	2.2

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Note 10 – Employee Benefits

Pension Plan

Certain Market Resources employees are covered by Questar’s defined benefit pension plan. Benefits are generally based on the employee’s age at retirement, years of service and highest earnings in a consecutive 72 semimonthly pay period during the 10 years preceding retirement. Questar is subject to and complies with minimum required and maximum allowed annual contribution levels mandated by the Employee Retirement Income Security Act and by the Internal Revenue Code. Subject to the above limitations, Questar intends to fund the qualified pension plan approximately equal to the yearly expense. Questar also has a nonqualified pension plan that covers certain management employees in addition to the qualified pension plan. The nonqualified pension plan provides for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee above the benefit limit defined by the Internal Revenue Service for the qualified plan. The no nqualified pension plan is unfunded. Claims are paid from the Company’s general funds. Qualified pension plan assets consist principally of equity securities and corporate and U.S. government debt obligations. A third-party consultant calculates the pension plan projected benefit obligation. Pension expense was $3.8 million, $4.6 million in 2007 and $4.9 million in 2006.

Market Resources portion of plan assets and benefit obligations cannot be determined because the plan assets are not segregated or restricted to meet the Company’s pension obligations. If the Company were to withdraw from the pension plan, the pension obligation for the Company’s employees would be retained by the pension plan. At December 31, 2008 and 2007, Questar’s projected benefit obligation exceeded the fair value of plan assets.

Postretirement Benefits Other Than Pensions

Eligible Market Resources employees participate in Questar’s postretirement benefits other than pensions plan. Postretirement health care benefits and life insurance are provided only to employees hired before January 1, 1997. The Company pays a portion of the costs of health care benefits, based on an employee’s years of service, and generally limits payments to 170% of the 1992 contribution. Plan assets consist of equity securities and corporate and U.S. government debt obligations. A third party consultant calculates the projected benefit obligation. The cost of postretirement benefits other than pensions was $1.3 million in 2008, 2007 and 2006.

The Company’s portion of plan assets and benefit obligations related to post-retirement medical and life insurance benefits cannot be determined because the plan assets are not segregated or restricted to meet the Company’s obligations. At December 31, 2008 and 2007, Questar’s accumulated benefit obligation exceeded the fair value of plan assets.

Employee Investment Plan  

Market Resources subsidiaries participate in Questar’s 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 Company currently contributes an overall match of 100% 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. Beginning in 2005, the EIP trustee has purchased Questar shares on the open market as cash contributions are received. The Company’s expense equaled its matching contribution of $4.1 million in 2008, $3.5 million in 2007and $2.4 million in 2006.

Note 11 – Related Party Transactions

Market Resources receives a portion of its revenues from services provided to affiliate, Questar Gas. The Company received $232.8 million in 2008, $171.6 million in 2007 and $176.4 million in 2006 for operating cost-of-service gas properties, gathering gas and supplying a portion of gas for resale, among other services provided to Questar Gas. Operation of cost-of-service gas properties is described in Wexpro Agreement (Note 12).

Market Resources pays Questar for certain administrative services. These payments were included in operating expenses and amounted to $10.7 million in 2008, $16.8 million in 2007 and $11.5 million in 2006. Questar allocates the costs based on each affiliate’s proportional share of revenues, net of gas costs; property, plant and equipment; and payroll. Management believes that the allocation method is reasonable.

Market Resources contracted for transportation and storage services with affiliate Questar Pipeline and was charged $2.1 million in 2008, $2.8 million in 2007 and $3.7 million in 2006 for these services.

Market Resources has a lease with Questar for space in an office building located in Salt Lake City, Utah, that expires January 12, 2012. The building is owned by a third party. The third party has a lease arrangement with Questar, which in turn sublets office space to affiliated companies. Market Resources was charged $1.1 million in 2008, $1.0 million in 2007 and $0.7 million in 2006.

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The Company loaned cash to affiliated companies and received interest income of $0.5 million in 2008, $4.5 million in 2007, and $3.4 million in 2006. Market Resources borrowed cash from affiliated companies and was charged interest expense of $3.8 million in 2008, $6.8 million in 2007 and $4.4 million in 2006.

Note 12 – Wexpro Agreement

Wexpro’s operations are subject to the terms of the Wexpro Agreement. The agreement was effective August 1, 1981, and sets forth the rights of Questar Gas utility operations to receive certain benefits from Wexpro’s operations. The agreement was approved by the PSCU and PSCW in 1981 and affirmed by the Supreme Court of Utah in 1983. Major provisions of the agreement are as follows.

a. Wexpro conducts gas-development drilling on a finite group of productive gas properties, as defined in the agreement, and bears any costs of dry holes. Natural gas produced from successful drilling on these properties is delivered to Questar Gas. Wexpro is reimbursed for the costs of producing the natural gas plus a return on its investment in successful wells. The after-tax return allowed Wexpro is adjusted annually and is approximately 20.6%.

b. Wexpro operates certain natural gas properties for Questar Gas. Wexpro is reimbursed for its costs of operating these properties, including a rate of return on any investment it makes. This after-tax rate of return is adjusted annually and is approximately 12.6%.

c. Crude-oil production from certain oil-producing properties is sold at market prices with the revenues used to recover operating expenses and to provide Wexpro a return on its investment. The after-tax rate of return on investments in these properties is adjusted annually and is approximately 12.6%. Any operating income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%.

d. Wexpro conducts developmental-oil drilling on productive oil properties and bears any costs of dry holes. Oil discovered from these properties is sold at market prices with the revenues used to recover operating expenses and to give Wexpro a return on its investment in successful wells. The after-tax rate of return is adjusted annually and is approximately 17.6%. Any operating income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas with Wexpro retaining 46%.

e. Amounts received by Questar Gas from the sharing of Wexpro’s oil income are used to reduce natural-gas costs to utility customers. Questar Gas received oil-income sharing of $6.1 million in 2008, $4.9 million in 2007 and $5.5 million in 2006.

Wexpro’s investment base, net of depreciation and deferred income taxes, and the yearly average rate of return for 2008 and the previous two years are shown in the table below:

	2008	2007	2006
Wexpro’s net investment base (in millions)	$410.6	$300.4	$260.6
Average annual rate of return (after tax)	19.9%	19.9%	19.9%

Note 13 – Operations by Line of Business

Market Resources’ major lines of business include gas and oil exploration and production (Questar E&P and Wexpro), midstream field services (Gas Management) and energy marketing (Energy Trading). 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 years ended December 31, 2008:

	Market Resources Consolidated	Interco. Transactions	Questar E&P	Wexpro		Gas Management		Energy Trading
	(in millions)
2008
Revenues
From unaffiliated customers	$2,297.2		$1,392.1	$31.1		$265.9		$608.1
From affiliated companies	232.9	($835.8)		209.9		24.3		834.5
Total Revenues	2,530.1	(835.8)	1,392.1	241.0		290.2		1,442.6
Operating expenses

29

Cost of natural gas and other products sold	575.1	(829.8)	0.5					1,404.4
Operating and maintenance	243.6	(1.5)	125.4	23.5		95.0		1.2
General and administrative	91.7	(4.5)	55.8	13.7		23.7		3.0
Production and other taxes	144.6		104.0	37.7		2.6		0.3
Depreciation, depletion and amortization	410.0		330.9	48.5		28.7		1.9
Other operating expenses	80.8		73.9	6.1		0.8
Total operating expenses	1,545.8	(835.8)	690.5	129.5		150.8		1,410.8
Net gain (loss) from asset sales	60.2		60.4	(0.2)
Operating income	1,044.5		762.0	111.3		139.4		31.8
Interest and other income	(64.6)	(68.6)	(71.7)	6.6				69.1
Income from unconsolidated affiliates	1.7		0.5			1.2
Interest expense	(62.2)	68.6	(58.3)	(2.7)		(3.6)		(66.2)
Income tax expense	(324.9)		(224.5)	(41.3)		(46.5)		(12.6)
Net income	594.5		408.0	73.9		90.5		22.1
Net income attributable to     noncontrolling interest	(9.0)					(9.0)
Net income attributable to Market Resources	$   585.5		$   408.0	$ 73.9		$  81.5		$ 22.1
Identifiable assets	$6,234.4		$4,508.0	$595.3		$917.6		$213.5
Investment in unconsolidated affiliates	40.8					40.8
Capital expenditures	2,280.5		1,777.3	143.8		357.9		1.5
Goodwill	60.2		60.2
2007
Revenues
From unaffiliated customers	$1,671.3		$   956.0	$  21.6		$189.3		$504.4
From affiliated companies	172.1	($484.7)		155.7		17.0		484.1
Total Revenues	1,843.4	(484.7)	956.0	177.3		206.3		988.5
Operating expenses
Cost of natural gas and other products sold	474.7	(482.8)	2.2					955.3
Operating and maintenance	187.9	(1.1)	87.9	16.5		83.6		1.0
General and administrative	91.3	(0.8)	56.3	14.7		17.2		3.9
Production and other taxes	81.6		60.1	20.0		1.4		0.1
Depreciation, depletion and amortization	295.1		243.5	31.2		19.1		1.3
Other operating expenses	38.1		32.8	4.9		0.4
Total operating expenses	1,168.7	(484.7)	482.8	87.3		121.7		961.6
Net (loss) from asset sales	(1.3)		(0.6)	(0.7)
Operating income	673.4		472.6	89.3		84.6		26.9
Interest and other income	15.4	(26.9)	6.2	1.9		0.2		34.0
Income from unconsolidated affiliates	8.9		0.4			8.5
Interest expense	(35.6)	26.9	(25.2)	(2.0)		(6.9)		(28.4)
Income tax expense	(241.3)		(168.5)	(30.0)		(31.1)		(11.7)
Net income attributable to Market Resources	$   420.8		$   285.5	$  59.2		$  55.3		$  20.8
Identifiable assets	$3,806.4		$2,524.5	$481.1		$494.2		$306.6
Investment in unconsolidated affiliates	52.8					52.8
Capital expenditures	943.9		708.5	105.0		128.3		2.1
Goodwill	60.9		60.9
2006
Revenues
From unaffiliated customers	$1,659.4		$  815.7		$   19.7		$168.0		$ 656.0
From affiliated companies	176.4	($687.8)			150.5		15.9		697.8
Total Revenues	1,835.8	(687.8)	815.7		170.2		183.9		1,353.8
Operating expenses

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Cost of natural gas and other products sold	652.6	(686.0)	2.8						1,335.8
Operating and maintenance	180.4	(1.1)	73.6		14.7		92.4		0.8
General and administrative	69.2	(0.7)	42.4		11.3		12.2		4.0
Production and other taxes	89.4		58.3		30.3		0.6		0.2
Depreciation, depletion and amortization	235.0		185.7		33.1		15.3		0.9
Other operating expenses	47.5		42.0		5.5
Total operating expenses	1,274.1	(687.8)	404.8		94.9		120.5		1,341.7
Net gain (loss) from asset sales	25.2		24.3		(0.1)		1.0
Operating income	586.9		435.2		75.2		64.4		12.1
Interest and other income (expense)	2.2	(27.0)	(3.7)		1.3				31.6
Income from unconsolidated affiliates	7.5		0.4				7.1
Interest expense	(33.9)	27.0	(27.1)		(0.5)		(4.7)		(28.6)
Income tax expense	(206.6)		(150.9)		(26.0)		(24.2)		(5.5)
Net income attributable to Market Resources	$   356.1		$   253.9		$  50.0		$  42.6		$    9.6
Identifiable assets	$3,249.6		$2,169.9		$397.1		$377.1		$305.5
Investment in unconsolidated affiliates	37.5						37.3		0.2
Capital expenditures	752.7		586.3		82.7		82.2		1.5
Goodwill	60.9		60.9

Note 14 – Unaudited Quarterly Financial Information

The quarterly information for the first, second and third quarters of 2007 was restated to correct for errors related to intercompany elimination of natural gas and crude oil sales between Questar E&P and Energy Trading. The restatements did not impact net income, operating income, the Consolidated Balance Sheets or the Consolidated Statements of Cash Flows. The Company filed amended Forms 10-Q in 2008 explaining the corrections. Following is a summary of quarterly financial information:

	First	Second	Third	Fourth
	Quarter	Quarter	Quarter	Quarter	Year
	(in millions)
2008
Revenues	$617.5	$680.5	$661.4	$570.7	$2,530.1
Operating income	222.7	259.9	353.6	208.3	1,044.5
Net income attributable to Market Resources	139.3	162.1	197.6	86.5	585.5
2007
Revenues as reported	$478.7	$430.6	$411.8	$522.3	$1,843.4
Revenues as restated	502.8	451.6	423.6	465.4	1,843.4
Operating income	165.5	173.1	167.7	167.1	673.4
Net income attributable to Market Resources	109.5	102.1	108.7	100.5	420.8

Note 15 – Supplemental Gas and Oil Information (Unaudited)

In accordance with SFAS 69 and Regulation S-X, the Company is making the following supplemental disclosures of gas and oil producing activities.

The Company uses the successful efforts accounting method for its gas and oil exploration and development activities and for cost-of-service gas and oil properties.

Questar E&P Activities

The following information is provided with respect to Questar E&P’s gas and oil exploration and production activities, which are all located in the United States.

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Capitalized Costs

The aggregate amounts of costs capitalized for gas and oil exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below:

	December 31,
	2008	2007
	(in millions)
Proved properties	$ 4,912.6	$ 3,306.9
Unproved properties	193.2	55.6
Support equipment and facilities	35.6	23.3
	5,141.4	3,385.8
Accumulated depreciation, depletion and amortization	(1,421.8)	(1,114.3)
	$ 3,719.6	$ 2,271.5

Costs Incurred

The costs incurred in gas and oil exploration and development activities are displayed in the table below. The development costs include expenditures to develop a portion of the proved undeveloped reserves reported at the end of the prior year. These costs were $219.9 million in 2008, $125.8 million in 2007 and $109.2 million in 2006.

	Year Ended December 31,
	2008	2007	2006
	(in millions)
Property acquisition
Unproved	$   125.1	$    1.0	$     8.8
Proved	602.7	45.1	20.6
Leaseholds	42.2	27.9	13.7
Exploration (capitalized and expensed)	60.1	25.4	34.5
Development	1,059.8	641.7	581.2
	$1,889.9	$741.1	$658.8

Results of Operation

Following are the results of operation of Questar E&P gas and oil exploration and development activities, before corporate overhead and interest expenses.

	Year Ended December 31,
	2008	2007	2006
	(in millions)
Revenues	$1,392.1	$956.0	$815.7
Production expenses	229.4	148.0	131.9
Exploration expenses	29.3	22.0	34.4
Depreciation, depletion and amortization	330.9	243.5	185.7
Abandonment and impairment	44.6	10.8	7.6
Total expenses	634.2	424.3	359.6
Revenues less expenses	757.9	531.7	456.1
Income taxes	(269.1)	(197.3)	(170.1)
Results of operation before corporate overhead   and interest expenses	$   488.8	$334.4	$286.0

Estimated Quantities of Proved Gas and Oil Reserves

Estimates of the Company’s proved gas and oil reserves have been prepared by Ryder Scott Company and Netherland, Sewell & Associates, Inc., independent reservoir engineers, in accordance with the SEC’s Regulation S-X and SFAS 69 “Disclosures about

32

Oil and Gas Producing Activities.” The table below summarizes the changes in the estimated net quantities of proved natural gas, oil and NGL reserves for each of the three years in the period ended December 31, 2008. The quantities reported are based on existing economic and operating conditions at the time the estimates were made. All gas and oil reserves reported are located in the United States. The Company does not have any long-term supply contracts with foreign governments or reserves of equity investees.

			Natural Gas
	Natural Gas	Oil and NGL	Equivalents
	(Bcf)	(MMbbl)	(Bcfe)(a)
Proved Reserves
Balance at January 1, 2006	1,324.8	25.9	1,480.4
Revisions -
Previous estimates	(38.9)	2.6	(23.8)
Pinedale increased-density(b)	163.0	1.2	170.4
Extensions and discoveries	119.1	1.2	126.6
Purchase of reserves in place	9.8	0.1	10.2
Sale of reserves in place	(2.7)		(2.8)
Production	(113.9)	(2.6)	(129.6)
Balance at December 31, 2006	1,461.2	28.4	1,631.4
Revisions -
Previous estimates	26.3	3.3	46.2
Pinedale increased-density(b)	120.6	1.0	126.8
Extensions and discoveries	172.6	3.3	192.7
Purchase of reserves in place	16.0	0.2	17.1
Sale of reserves in place	(6.3)		(6.4)
Production	(121.9)	(3.0)	(140.2)
Balance at December 31, 2007	1,668.5	33.2	1,867.6
Revisions -
Previous estimates	(128.5)	(4.0)	(152.9)
Pinedale increased-density(b)	154.5	1.2	161.8
Extensions and discoveries	208.0	5.2	239.1
Purchase of reserves in place	289.8	0.4	292.4
Sale of reserves in place	(11.9)	(1.1)	(18.5)
Production	(151.9)	(3.3)	(171.4)
Balance at December 31, 2008	2,028.5	31.6	2,218.1
Proved-Developed Reserves
Balance at January 1, 2006	792.0	21.4	920.5
Balance at December 31, 2006	852.0	23.1	990.7
Balance at December 31, 2007	987.4	26.7	1,147.4
Balance at December 31, 2008	1,128.1	23.6	1,269.4

^(a)Natural Gas Equivalents – oil 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.

^(b)Estimates of the quantity of proved reserves from the Company’s Pinedale Anticline leasehold in western Wyoming have changed substantially over time as a result of numerous factors including, but not limited to, additional development drilling activity, producing well performance and an improved understanding of Lance Pool reservoir characteristics. The continued analysis of new data has led to progressive increases in estimates of original gas-in-place in the Lance Pool reservoirs at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. The Wyoming Oil and Gas Conservation Commission (WOGCC) has approved 10-acre-density drilling for Lance Pool wells on about 12,700 (gross) of the Company’s 17,872 acre (gross) Pinedale leasehold. The area approved for increased density corresponds to

33

the estimated productive limits of the Company’s core acreage in the field. In January 2008, the WOGCC approved five-acre-density drilling for Lance Pool wells on about 4,200 gross acres of Market Resources Pinedale leasehold. If five-acre-density development is appropriate for a majority of its leasehold, the Company currently estimates up to an additional 1,600 wells will be required to fully develop the Lance Pool on its acreage. The Company will continue to disclose future revisions to proved reserves associated with Pinedale increased density drilling separately.

Standardized Measure of Future Net Cash Flows Relating to Proved Reserves

Future net cash flows were calculated at December 31 using year-end prices and known contract-price changes. The year-end prices do not include any impact of hedging activities. The average year-end price per Mcf of proved natural gas reserves was $4.62 in 2008, $6.01 in 2007 and $4.47 in 2006. The average year-end price per barrel of proved oil and NGL reserves combined was $28.41 in 2008, $80.86 in 2007 and $51.49 in 2006. Year-end production costs, development costs and appropriate statutory income tax rates, with consideration of future tax rates already legislated, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop booked proved undeveloped reserves are $438.4 million in 2009, $421.7 million in 2010 and $298.7 million in 2011. At the end of this three-year period the Company expects to have evaluated about 56% of the cu rrent booked proved undeveloped reserves.

The assumptions used to derive the standardized measure of future net cash flows are those required by accounting standards and do not necessarily reflect the Company’s expectations. The usefulness of the standardized measure of future net cash flows is impaired because of the reliance on reserve estimates and production schedules that are inherently imprecise.

Management considers a number of factors when making investment and operating decisions. They include estimates of probable and proved reserves and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.

	Year Ended December 31,
	2008	2007		2006
	(in millions)
Future cash inflows	$10,263.4	$12,704.3	$  7,985.1
Future production costs	(2,717.6)	(2,863.4)	(2,133.0)
Future development costs	(1,884.0)	(1,232.4)	(1,026.9)
Future income tax expenses	(1,241.3)	(2,668.8)	(1,396.2)
Future net cash flows	4,420.5	5,939.7	3,429.0
10% annual discount to reflect timing of net cash flows	(2,418.6)	(3,105.7)	(1,861.2)
Standardized measure of discounted future net cash flows	$  2,001.9	$ 2,834.0	$  1,567.8

The principal sources of change in the standardized measure of discounted future net cash flows were:

	Year Ended December 31,
	2008	2007	2006
	(in millions)
Balance at January 1,	$2,834.0	$1,567.8	$2,707.1
Sales of gas and oil produced, net of production costs	(1,162.7)	(808.0)	(683.8)
Net changes in prices and production costs	(1,306.1)	1,554.6	(1,994.3)
Extensions and discoveries, less related costs	438.7	523.6	233.1
Revisions of quantity estimates	16.3	470.0	269.9
Net purchases and sales of reserves in place	625.0	41.8	(7.5)
Cost to develop proved undeveloped reserves	219.9	125.8	109.2
Change in future development	(662.6)	(214.5)	(259.6)
Accretion of discount	410.7	221.0	411.0
Net change in income taxes	711.2	(635.0)	760.8

34

Other	(122.5)	(13.1)	21.9
Net change	(832.1)	1,266.2	(1,139.3)
Balance at December 31,	$2,001.9	$2,834.0	$1,567.8

Cost-of-Service Activities

The following information is provided with respect to cost-of-service gas and oil properties managed and developed by Wexpro and governed by the Wexpro Agreement. Information on the standardized measure of future net cash flows has not been included for cost-of-service activities because the operations of and return on investment for such properties are regulated by the Wexpro Agreement.

Capitalized Costs

Capitalized costs for cost-of-service gas and oil properties net of the related accumulated depreciation and amortization are shown below.

	December 31,
	2008	2007
	(in millions)
Wexpro	$536.6	$434.7
Questar Gas	11.2	12.2
	$547.8	$446.9

Costs Incurred

Costs incurred by Wexpro for cost-of-service gas and oil-producing activities were $148.0 million in 2008, $110.7 million in 2007 and $100.3 million in 2006.

Results of Operation

Following are the results of operation of cost-of-service gas and oil-development activities, before corporate overhead and interest expenses:

	Year Ended December 31,
	2008	2007	2006
	(in millions)
Revenues
From unaffiliated companies	$  31.1	$  21.6	$  19.7
From affiliates(a)	209.9	155.7	150.5
Total revenues	241.0	177.3	170.2
Production expenses	67.3	41.4	50.5
Depreciation and amortization	48.5	31.2	33.1
Total expenses	115.8	72.6	83.6
Revenues less expenses	125.2	104.7	86.6
Income taxes	(44.9)	(35.2)	(29.6)
Results of operation before corporate overhead and interest expense	$  80.3	$  69.5	$  57.0

^(a)Primarily represents revenues received from Questar Gas pursuant to the Wexpro Agreement.

Estimated Quantities of Cost-of-Service Proved Gas and Oil Reserves

Because gas reserves managed, developed and produced by Wexpro are delivered to Questar Gas at cost-of-service, SEC guidelines with respect to standard economic assumptions are not applicable. The SEC anticipated this potential difficulty and provides that companies may give appropriate recognition to differences arising because of the effect of the ratemaking process. Accordingly, Wexpro uses a minimum-producing rate or maximum well-life limit to determine the ultimate quantity of reserves attributable to each well. The following estimates were made by the Wexpro’s reservoir engineers:

35

			Natural Gas
	Natural Gas	Oil and NGL	Equivalents
	(Bcf)	(MMbbl)	(Bcfe)(a)
Proved Reserves
Balance at January 1, 2006	497.3	3.9	520.5
Revisions-
Previous estimates	22.3	(0.1)	21.5
Pinedale increased-density(b)	100.0	0.8	104.6
Extensions and discoveries	39.8	0.2	41.3
Production	(38.8)	(0.4)	(40.9)
Balance at December 31, 2006	620.6	4.4	647.0
Revisions-
Previous estimates	(29.9)		(30.0)
Pinedale increased-density(b)	24.6	0.2	25.9
Extensions and discoveries	35.5	0.1	36.4
Production	(34.9)	(0.4)	(37.4)
Balance at December 31, 2007	615.9	4.3	641.9
Revisions-
Previous estimates	(19.6)	(0.1)	(20.2)
Pinedale increased-density(b)	65.1	0.5	68.2
Extensions and discoveries	31.6	0.2	32.6
Production	(46.1)	(0.4)	(48.6)
Balance at December 31, 2008	646.9	4.5	673.9
Proved Developed Reserves
Balance at January 1, 2006	406.6	3.1	425.2
Balance at December 31, 2006	440.6	2.9	458.2
Balance at December 31, 2007	439.4	2.9	456.9
Balance at December 31, 2008	471.4	3.1	489.9

^(a)Natural Gas Equivalents – oil 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.

^(b)The area approved by the WOGCC for 10-acre-density drilling of Lance Pool wells corresponds to the estimated productive limits of the Company’s core acreage in the field. The Company will continue to disclose future revisions to proved reserves associated with Pinedale increased-density drilling separately.

Note 16 – Adoption of SFAS 160

In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51.” SFAS 160 establishes new accounting and reporting standards for noncontrolling interests (formally known as “minority interests”) in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 became effective for the Company beginning January 1, 2009, and requires retroactive adoption of the presentation and disclosure requirements for existing minority interests but prospective adoption of all of its other requirements. The Company has updated its financial statements for prior periods to reflect the adoption of the standard as of the earliest period presented. As a result of the adoption, minority interests are now referred to as noncontrolling interests, noncontrolling interests are now included in total equity in the consolidated balance sheets, and amounts previously described as net income are now described as net inco me attributable to Market Resources.

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QUESTAR MARKET RESOURCES, INC.
Schedule of Valuation and Qualifying Accounts
		Column C		Column D
Column A	Column B	Amounts charged		Deductions for	Column E
Description	Beginning Balance	to expense		accounts written off	Ending Balance
(in millions)
Year-Ended December 31, 2008
Allowance for bad debts	$3.3		$0.4	($1.0)	$2.7
Year Ended December 31, 2007
Allowance for bad debts	4.3		0.1	(1.1)	3.3
Year Ended December 31, 2006
Allowance for bad debts	2.9		1.4		4.3

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