Edgar Filing: QUESTAR MARKET RESOURCES INC

UNITED STATES

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]

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

For the quarter ended March 31, 2009

[ ]

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

For the transition period from ___ to ___

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 or organization

(Commission File Number)

(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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [ ] No [ ]

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

Large accelerated filer

[ ]

Accelerated filer

[ ]

Non-accelerated filer

[X] (Do not check if a smaller reporting company)

Smaller reporting company

[ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [ ] No [X]

On April 30, 2009, 4,309,427 shares of the registrant’s common stock, $1.00 par value, were outstanding. All shares are owned by Questar Corporation.

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

Questar Market Resources, Inc.

Form 10-Q for the Quarter Ended March 31, 2009

TABLE OF CONTENTS

Page

PART I.

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS (Unaudited)

Consolidated Statements of Income for the three months ended

March 31, 2009 and 2008

Condensed Consolidated Balance Sheets as of March 31, 2009

and December 31, 2008

Condensed Consolidated Statements of Cash Flows for the three months ended

March 31, 2009 and 2008

Notes Accompanying the Condensed Consolidated Financial Statements

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

ITEM 4.

CONTROLS AND PROCEDURES

PART II.

OTHER INFORMATION

Questar Market Resources 2009 Form 10-Q

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	3 Months Ended March 31,
	2009	2008
	(in millions)
REVENUES
From unaffiliated customers	$472.7	$565.6
From affiliated companies	65.7	51.9
Total Revenues	538.4	617.5

OPERATING EXPENSES
Cost of natural gas and other products sold (excluding operating expenses shown separately)	105.9	182.0
Operating and maintenance	61.2	57.0
General and administrative	23.3	23.0
Production and other taxes	22.7	34.8
Depreciation, depletion and amortization	139.7	89.7
Exploration	3.1	3.5
Abandonment and impairment	3.7	2.6
Wexpro Agreement-oil income sharing		2.0
Total Operating Expenses	359.6	394.6
Net gain (loss) from asset sales	1.8	(0.2)
OPERATING INCOME	180.6	222.7
Interest and other income	2.4	0.9
Income from unconsolidated affiliates	0.6	0.2
Net mark-to-market gain (loss) on basis-only swaps	(134.9)	13.7
Interest expense	(16.2)	(12.6)
INCOME BEFORE INCOME TAXES	32.5	224.9
Income taxes	(11.3)	(83.2)
NET INCOME	21.2	141.7
Net income attributable to noncontrolling interest	(0.5)	(2.4)
NET INCOME ATTRIBUTABLE TO MARKET RESOURCES	$ 20.7	$139.3

See notes accompanying the condensed consolidated financial statements

Questar Market Resources 2009 Form 10-Q

QUESTAR MARKET RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31,	December 31,
	2009 (Unaudited)	2008
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents		$ 20.3
Federal income taxes receivable		11.1
Accounts receivable, net	$ 194.0	265.2
Accounts receivable from affiliates	29.1	28.1
Fair value of derivative contracts	473.4	431.3
Gas and oil storage	8.6	23.6
Materials and supplies	113.4	86.8
Prepaid expenses and other	25.1	28.0
Total Current Assets	843.6	894.4
Property, Plant and Equipment	7,304.3	7,070.8
Accumulated depreciation, depletion and amortization	(2,097.2)	(1,964.4)
Net Property, Plant and Equipment	5,207.1	5,106.4
Investment in unconsolidated affiliates	41.3	40.8
Goodwill	60.1	60.2
Fair value of derivative contracts	114.8	106.3
Other noncurrent assets	22.1	26.3
Total Assets	$6,289.0	$6,234.4

LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$ 14.1
Notes payable to Questar	28.9	$ 89.4
Accounts payable and accrued expenses	317.0	477.4
Accounts payable to affiliates	17.0	14.1
Fair value of derivative contracts	9.1	0.5
Deferred income taxes – current	166.3	138.1
Total Current Liabilities	552.4	719.5
Long-term debt	1,349.1	1,299.1
Deferred income taxes	1,141.0	1,138.3
Asset retirement obligations	176.3	171.2
Fair value of derivative contracts	156.3	69.0
Other long-term liabilities	60.7	57.9
EQUITY
Common stock	4.3	4.3
Additional paid-in capital	114.5	141.9
Retained earnings	2,278.5	2,262.1
Accumulated other comprehensive income	397.8	341.6
Total Common Shareholder’s Equity	2,795.1	2,749.9
Noncontrolling interest	58.1	29.5
Total Equity	2,853.2	2,779.4
Total Liabilities and Equity	$6,289.0	$6,234.4

See notes accompanying the condensed consolidated financial statements

Questar Market Resources 2009 Form 10-Q

QUESTAR MARKET RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	3 Months Ended March 31,
	2009	2008
	(in millions)
OPERATING ACTIVITIES
Net income	$ 21.2	$141.7
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation, depletion and amortization	140.0	90.2
Deferred income taxes	(2.5)	59.5
Abandonment and impairment	3.7	2.6
Share-based compensation	3.7	2.7
Net (gain) loss from asset sales	(1.8)	0.2
(Income) from unconsolidated affiliates	(0.6)	(0.2)
Distributions from unconsolidated affiliates and other		0.8
Net mark-to-market (gain) loss on basis-only swaps	134.9	(13.7)
Changes in operating assets and liabilities	25.9	(7.7)
NET CASH PROVIDED FROM OPERATING ACTIVITIES	324.5	276.1

INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(350.0)	(951.3)
Other investments		(1.5)
Total capital expenditures	(350.0)	(952.8)
Proceeds from disposition of assets	5.9	0.3
NET CASH USED IN INVESTING ACTIVITIES	(344.1)	(952.5)

FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	14.1	9.9
Change in notes receivable from Questar		103.2
Change in notes payable to Questar	(60.5)	(29.4)
Change in short-term debt		50.0
Long-term debt issued, net of issuance costs	50.0	648.3
Long-term debt repaid		(100.0)
Distribution to noncontrolling interest		(2.3)
Other		1.0
Dividends paid	(4.3)	(4.3)
NET CASH PROVIDED FROM (USED IN) FINANCING ACTIVITIES	(0.7)	676.4
Change in cash and cash equivalents	(20.3)
Beginning cash and cash equivalents	20.3
Ending cash and cash equivalents	$ -	$ -

See notes accompanying the condensed consolidated financial statements

Questar Market Resources 2009 Form 10-Q

QUESTAR MARKET RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – 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 four principal subsidiaries:

Questar Exploration and Production Company (Questar E&P) acquires, explores for, develops and produces natural gas, oil, and natural gas liquids (NGL);

Wexpro Company (Wexpro) manages, develops and produces cost-of-service reserves for gas utility affiliate, Questar Gas Company (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 natural gas and oil, provides risk-management services, and owns and operates an underground gas-storage reservoir.

Market Resources operates in the Rocky Mountain and Midcontinent regions of the United States of America and is headquartered in Salt Lake City, Utah. Principal offices are located in Denver, Colorado; Oklahoma City, Oklahoma; Tulsa, Oklahoma; and Rock Springs, Wyoming.

Note 2 – Basis of Presentation of Interim Consolidated Financial Statements

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

On January 1, 2009, Market Resources adopted Statement of Financial Accounting Standards (SFAS) 160 “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51.” SFAS 160 requires ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the Consolidated Balance Sheets within shareholders’ 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 the former subsidiary be initially measured at fair value.

The condensed consolidated financial statements reflect all normal, recurring adjustments and accruals that are, in the opinion of management, necessary for a fair presentation of financial position and results of operations for the interim periods presented. Interim condensed consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. Certain reclassifications were made to prior-period financial statements to conform with the current presentation.

The preparation of the condensed consolidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect the amounts of revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three months ended March 31, 2009, are not necessarily indicative of the results that may be expected for the year ending December 31, 2009.

All dollar and share amounts in this quarterly report on Form 10-Q are in millions, except where otherwise noted.

Questar Market Resources 2009 Form 10-Q

Note 3 – 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) and accounts for the transactions according to SFAS 123R “Share-Based Payment.” Questar has granted and continues to grant share-based compensation to certain Market Resources employees. First-quarter share-based compensation expense amounted to $3.7 million in 2009 compared with $2.7 million in 2008.

Questar 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:


			February 2009
Fair value of options at grant date			$35.38
Risk-free interest rate			1.78%
Expected price volatility			28.1%
Expected dividend yield			1.39%
Expected life in years			5.0

Unvested stock options increased by 508,000 shares in the first three months of 2009. Stock-option transactions under the terms of the LTSIP are summarized below:


	Outstanding Options	Price Range	Weighted- average Price
Balance at January 1, 2009	1,470,450	$ 7.50 – $41.08	$20.16
Granted	528,000	35.38	35.38
Exercised	(59,500)	8.50 – 14.01	10.43
Employee transfers	6,000	11.48 – 13.56	13.21
Balance at March 31, 2009	1,944,950	$ 7.50 – $41.08	$24.57


	Options Outstanding			Options Exercisable		Unvested Options
Range of exercise prices	Number outstanding at Mar. 31, 2009	Weighted-average remaining term in years	Weighted-average exercise price	Number exercisable at Mar. 31, 2009	Weighted-average exercise price	Number unvested at Mar. 31, 2009	Weighted-average exercise price
$ 7.50	81,616	0.9	$ 7.50	81,616	$ 7.50
11.48 - 11.98	367,842	2.9	11.71	367,842	11.71
13.56 - 14.01	405,718	3.5	13.65	405,718	13.65
17.55 - 28.58	301,774	2.7	28.06	14,274	17.55	287,500	$28.58
$35.38 - $41.08	788,000	6.0	36.62	20,000	41.08	768,000	36.51
	1,944,950	4.1	$24.57	889,450	$12.96	1,055,500	$34.35

Restricted-share grants typically vest in equal installments over a three to four year period from the grant date. Several grants vest in a single installment after a specified period. The weighted-average vesting period of unvested restricted shares at March 31, 2009, was 20 months. Transactions involving restricted shares in the LTSIP are summarized below:

Questar Market Resources 2009 Form 10-Q


	Restricted		Weighted-average
	Shares	Price Range	Price
Balance at January 1, 2009	599,677	$25.12 – $70.13	$46.35
Granted	171,900	33.98 – 36.50	35.38
Distributed	(142,912)	25.50 – 57.47	36.21
Forfeited	(1,900)	49.97 – 62.50	55.91
Balance at March 31, 2009	626,765	$25.12 – $70.13	$45.63

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 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 by Company personnel based on retirement costs of similar properties (Level 3 inputs under the provisions of SFAS 157) available to field operations and depreciated over the life of the related assets. Revisions to ARO estimates result from changes in expected cash flows. Income or expense resulting from the settlement of ARO liabilities is included in other income on the Consolidated Statements of Income. 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:


Level 3	2009	2008
	(in millions)
ARO liability at January 1,	$171.2	$145.3
Accretion	2.6	2.2
Liabilities incurred	0.8	4.2
Revisions	2.4	1.5
Liabilities settled	(0.7)	(0.2)
ARO liability at March 31,	$176.3	$153.0

Wexpro collects from Questar Gas and deposits in trust certain funds related to estimated ARO costs. The funds are used to satisfy retirement obligations as the properties are abandoned and recorded in other noncurrent assets on the Consolidated Balance Sheets. Trust funds are invested primarily in a money-market account with a balance of $10.3 million at March 31, 2009. The fair value of Wexpro’s trust is based on asset summary statements provided by the bank holding the trust and considered Level 2 under the provisions of SFAS 157.

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 costs have been capitalized for less than one year.


	2009	2008
	(in millions)
Balance at January 1,	$ 17.0	$1.5
Additions to capitalized exploratory well costs pending the determination of proved reserves	8.3
Reclassifications to property, plant and equipment after the determination of proved reserves	(14.3)
Balance at March 31,	$ 11.0	$1.5

Questar Market Resources 2009 Form 10-Q

Note 6 – Fair-Value Measures

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. SFAS 157 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. The Level 2 fair value of derivative contracts is located in Note 7. The fair value of these derivative contracts is based on market prices posted on the NYMEX on the last trading day of the reporting period.

In February 2008, the FASB issued FASB Staff Position Financial Accounting Standard 157-2 “Partial Deferral of the Effective Date of Statement 157,” which delayed the effective date of SFAS 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis. On January 1, 2009, Market Resources adopted, without material impact on the consolidated financial statements, the provisions of SFAS 157 related to nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which includes, among other things, asset retirement obligations. The initial valuation of asset retirement obligations is a Level 3 fair value and is discussed in Note 4.

Note 7 – Derivative Contracts

Commodity-Price Risk Management

Market Resources’ subsidiaries use gas- and oil-price-derivatives in the normal course of business to reduce, or hedge, the risk of adverse commodity-price movements. However, these same arrangements typically limit future gains from favorable price movements. Derivative contracts are currently in place for a significant share of Questar E&P-owned gas and oil production and a portion of Energy Trading gas- and oil-marketing transactions. On January 1, 2009, the Company adopted SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities,” which requires more detailed information about hedging transactions including the location and effect on the primary consolidated financial statements.

Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. These policies and procedures are reviewed periodically by the Finance and Audit Committee of the Company’s Board of Directors. Market Resources hedges natural gas and oil prices to support rate of return and cash-flow targets and protect earnings from downward movements in commodity prices. The volume of hedged production and the mix of derivative instruments are regularly evaluated and adjusted by management in response to changing market conditions. Market Resources may hedge up to 100% of forecast production from proved reserves when prices meet earnings and cash-flow objectives. Market Resources does not enter into derivative arrangements for speculative purposes.

Market Resources uses fixed-price swaps to realize a known price for a specific volume of production delivered into a regional sales point. A fixed-price swap is a derivative instrument that exchanges or “swaps” the “floating” or daily price of a specified volume of natural gas, oil or NGL, over a specified period, for a fixed price for the specified volume over the same period (typically three months or longer). In the normal course of business, the Company sells its equity natural gas, oil and NGL production to third parties at first-of-the-month or daily “floating” prices related to indices reported in industry publications. The fixed-price swap price is reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price. Swap agreements do not require the physical transfer of gas between the parties at settlement. Swap transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the relevant volume, for the settlement period.

Market Resources enters into commodity-price derivative arrangements that do not have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement dates. The amount of credit available under these arrangements may vary depending on the credit ratings assigned to Market Resources’ debt. Derivative-arrangement counterparties are normally banks and energy-trading firms with investment-grade credit ratings. The Company regularly monitors counterparty exposure, credit worthiness and performance.

Generally, derivative instruments are matched to equity gas and oil production, thus qualifying as cash-flow hedges. Changes in the fair value of cash-flow hedges are recorded on the Consolidated Balance Sheets and in accumulated other comprehensive income (loss) until the underlying gas or oil is produced. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. The ineffective portion of cash-flow hedges is immediately recognized in the determination of net income.

Questar Market Resources 2009 Form 10-Q

Also, Questar E&P may use natural gas 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. However, natural gas basis-only swaps expose the Company to losses from narrowing natural gas-price basis differentials. A basis-only swap does not qualify for hedge accounting treatment. These contracts are marked to market with any change in the valuation recognized in the determination of net income. The net mark-to-market effect of basis-only swaps is reported in the Consolidated Statements of Income below operating income.


	3 Months Ended March 31,
	2009
	(in millions)
*Effect of derivative instruments designated as hedges*
Revenues
Fixed-price swaps increased revenues	$155.1
Cost Of Natural Gas And Other Products Sold
Fixed-price swaps increased product costs	0.6
*Effect of derivative instruments not designated as hedges*
Net mark-to-market (loss) on basis-only swaps	($134.9)

Settlements for the first three months of 2009 resulted in a transfer of $78.9 million after-tax income from Accumulated Other Comprehensive Income to revenues in the Consolidated Statements of Income. In the next 12 months $318.5 million or 80% of the $397.8 million after-tax unrealized income in Accumulated Other Comprehensive Income will be settled and transferred to revenues in the Consolidated Statements of Income. The following table discloses Level 2 fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation on the Condensed Consolidated Balance Sheets. The fair value of these derivative contracts is based on market prices posted on the NYMEX on the last trading day of the reporting period.


Level 2	March 31, 2009
	(in millions)
*Assets*
Fixed-price swaps	$513.9
Basis-only swaps	12.8
Fair value of derivative instruments - short term	$526.7
Fixed-price swaps	$139.1
Basis-only swaps	1.3
Fair value of derivative instruments - long term	$140.4
*Liabilities*
Fixed-price swaps	$ 7.0
Basis-only swaps	55.4
Fair value of derivative instruments - short term	$ 62.4
Fixed-price swaps	$ 12.8
Basis-only swaps	169.1
Fair value of derivative instruments - long term	$181.9

Market Resources’ derivative contracts as of March 31, 2009, are summarized below:

Questar Market Resources 2009 Form 10-Q

Questar E&P Equity Production


Year	Time Periods	Quantity	Average price per Mcf, net to the well
			Estimated
Gas (Bcf) Fixed-price Swaps
2009	9 months	97.2	$7.65
2010	12 months	86.6	6.71
2011	12 months	6.7	4.63

Gas (Bcf) Basis-only Swaps
2009	9 months	19.2	2.49
2010	12 months	54.0	2.92
2011	12 months	98.5	2.10

Oil (Mbbl) Fixed-price Swaps,
			Average price per Bbl, net to the well
2009	9 months	550	$62.95

Energy Trading Marketing Transactions


Year	Time Periods	Quantity	Average price per MMBtu
Gas Sales (MMBtu) Fixed-price Swaps
2009	9 months	4,917	$4.96
2010	12 months	610	5.69



Gas Purchases (MMBtu) Fixed-price Swaps
2009	9 months	2,877	$4.50
2010	12 months	610	5.60

Note 8 – Change in Ownership Interest

Gas Management constructed a gathering pipeline for $201.3 million and contributed the asset to Rendezvous Gas Services LLC (Rendezvous). Gas Management’s ownership interest increased from 50% to 78%. As a result additional paid-in capital was reduced by $31.1 million and noncontrolling interest increased by $28.1 million. Rendezvous operates gas-gathering facilities for Pinedale Anticline and Jonah field producers for delivery to various interstate pipelines. Beginning in 2008, Gas Management consolidated the operations of Rendezvous for financial reporting purposes.

Note 9 – 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:

Questar Market Resources 2009 Form 10-Q


	3 Months Ended March 31,
	2009	2008
	(in millions)
*Revenues from Unaffiliated Customers*
Questar E&P	$307.4	$299.7
Wexpro	2.4	8.3
Gas Management	48.3	63.1
Energy Trading and other	114.6	194.5
Total	$472.7	$565.6

*Revenues from Affiliated Companies*
Wexpro	$ 59.5	$ 46.4
Gas Management	6.7	5.8
Energy Trading and other	93.2	226.3
Subtotal	159.4	278.5
Intercompany eliminations	(93.7)	(226.6)
Total	$ 65.7	$ 51.9

*Operating Income*
Questar E&P	$123.8	$152.0
Wexpro	28.9	25.4
Gas Management	19.6	33.1
Energy Trading and other	8.3	12.2
Total	$180.6	$222.7

*Net Income (Loss) Attributable to Market Resources*
Questar E&P	($14.9)	$ 96.5
Wexpro	18.8	16.2
Gas Management	11.4	18.5
Energy Trading and other	5.4	8.1
Total	$20.7	$139.3

Note 10 – Comprehensive Income

Comprehensive income is the sum of net income attributable to Market Resources as reported in the Consolidated Statements of Income and other comprehensive income (loss). Other comprehensive income (loss) includes changes in the market value of gas- and oil-price derivatives. Changes in the market value of derivatives during the period result from contracts realized or otherwise settled, changes in energy prices and new derivative contracts. Comprehensive income (loss) attributable to Market Resources is shown below:

Questar Market Resources 2009 Form 10-Q


	3 Months Ended March 31,
	2009	2008
	(in millions)
Net income	$ 21.2	$141.7
Other comprehensive income (loss)
Net unrealized income (loss) on derivatives	89.6	(310.9)
Income taxes	(33.4)	117.8
Net other comprehensive income (loss)	56.2	(193.1)
Comprehensive income (loss)	77.4	(51.4)
Net income attributable to noncontrolling interest	(0.5)	(2.4)
Total comprehensive income (loss) attributable to Market Resources	$ 76.9	($ 53.8)

Note 11 – Recent Accounting Development

In April 2009, the FASB issued FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” which provides additional guidance for estimating fair value when the level of activity for the asset or liability has significantly decreased. This FSP clarifies and includes additional factors to consider in determining whether there has been a significant decrease in market activity for an asset or liability and estimating fair value when the market activity for an asset or liability has declined significantly. The scope of this FSP does not include assets and liabilities measured under Level 1 inputs. FSP SFAS 157-4 is applied prospectively to all fair value measurements where appropriate and will be effective for interim and annual periods ending after June 15, 2009. The adoption of FSP SFAS 157-4 is not expected to have a material impact on financial position or results of operations.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following information updates the discussion of Market Resources’ financial condition provided in its 2008 Form 10-K filing, and analyzes the changes in the results of operations between the three month periods ended March 31, 2009 and 2008. For definitions of commonly used gas and oil terms found in this report on Form 10-Q, please refer to the “Glossary of Commonly Used Terms” provided in the Company’s 2008 Form 10-K.

RESULTS OF OPERATIONS

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


	3 Months Ended March 31,
	2009	2008	Change
	(in millions)
Exploration and Production
Questar E&P	($ 14.9)	$ 96.5	($111.4)
Wexpro	18.8	16.2	2.6
Midstream Field Services - Gas Management	11.4	18.5	(7.1)
Energy Marketing - Energy Trading and other	5.4	8.1	(2.7)
Net income attributable to Market Resources	$ 20.7	$139.3	($118.6)

Questar Market Resources 2009 Form 10-Q

EXPLORATION AND PRODUCTION

Questar E&P

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


	3 Months Ended March 31,
	2009	2008		Change
	(in millions)
Operating Income
REVENUES
Natural gas sales	$275.0	$239.8	$35.2
Oil and NGL sales	31.1	58.4	(27.3)
Other	1.3	1.5	(0.2)
Total Revenues	307.4	299.7	7.7
OPERATING EXPENSES
Operating and maintenance	34.4	28.0	6.4
General and administrative	15.6	14.2	1.4
Production and other taxes	15.4	27.0	(11.6)
Depreciation, depletion and amortization	113.3	71.8	41.5
Exploration	3.1	3.5	(0.4)
Abandonment and impairment	3.7	2.6	1.1
Natural gas purchases		0.4	(0.4)
Total Operating Expenses	185.5	147.5	38.0
Net gain (loss) from asset sales	1.9	(0.2)	2.1
Operating Income	$123.8	$152.0	($28.2)
Operating Statistics
Questar E&P production volumes
Natural gas (Bcf)	41.4	34.8	6.6
Oil and NGL (MMbbl)	0.9	0.8	0.1
Total production (Bcfe)	46.9	39.5	7.4
Average daily production (MMcfe)	521.3	433.8	87.5
Questar E&P average realized price, net to the well (including hedges)
Natural gas (per Mcf)	$ 6.64	$ 6.90	($ 0.26)
Oil and NGL (per bbl)	34.09	74.18	(40.09)

Questar E&P reported a net loss of $14.9 million in the first quarter, down 115% from net income of $96.5 million in the 2008 quarter. The company reported production of 46.9 Bcfe in the first quarter of 2009 compared to 39.5 Bcfe in the 2008 quarter, a 19% increase. The growth in production offset lower realized natural gas, crude oil and NGL prices but net mark-to-market losses on natural gas basis-only swaps and an 8% increase in per unit production costs resulted in reduced net income compared to the prior year period. Net mark-to-market losses on natural gas basis-only swaps decreased first-quarter 2009 net income $84.7 million, compared to an $8.6 million after-tax gain in the 2008 period.

Natural gas is Questar E&P’s primary focus. On an energy-equivalent basis, natural gas comprised approximately 88% of Questar E&P 2009 production. A comparison of natural gas-equivalent production by major operating area is shown in the following table:

Questar Market Resources 2009 Form 10-Q


	3 Months Ended March 31,
	2009	2008	Change
	(in Bcfe)
Pinedale Anticline	14.6	13.3	1.3
Uinta Basin	6.3	6.7	(0.4)
Rockies Legacy	5.0	4.9	0.1
Total Rocky Mountain	25.9	24.9	1.0
Midcontinent	21.0	14.6	6.4
Total Questar E&P	46.9	39.5	7.4

Total production increased 19% in the first quarter of 2009 compared to a year earlier. Questar E&P production from the Pinedale Anticline in western Wyoming grew 10% to 14.6 Bcfe in the first quarter of 2009 as a result of ongoing development drilling. In the Uinta Basin, production decreased 6% to 6.3 Bcfe in 2009 due to decreased drilling activity. Questar E&P Rockies Legacy properties include all of the Company’s Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin. Rockies Legacy 2009 production of 5.0 Bcfe was 0.1 Bcfe higher than a year ago; primarily as a result of increased production in the Wamsutter Arch and Williston Basin areas.

In the Midcontinent, production grew 44% to 21.0 Bcfe in 2009 and included 5.1 Bcfe of production from development properties in northwest Louisiana acquired on February 29, 2008. Ongoing development drilling in the Elm Grove and Woodardville fields in northwestern Louisiana and continued development of the Company’s Texas Panhandle Granite Wash play were the main contributors to the production increase.

Realized prices for natural gas, oil and NGL at Questar E&P were lower when compared to the prior year. In 2009, the weighted-average realized natural gas price for Questar E&P (including the impact of hedging) was $6.64 per Mcf compared to $6.90 per Mcf for the same period in 2008, a 4% decrease. Realized oil and NGL prices in 2009 averaged $34.09 per bbl, compared with $74.18 per bbl during the prior year period, a 54% decrease. A regional comparison of average realized prices, including hedges, is shown in the following table:


	3 Months Ended March 31,
	2009	2008	Change
*Natural gas (per Mcf)*
Rocky Mountains	$ 5.87	$ 6.37	($0.50)
Midcontinent	7.57	7.84	(0.27)
Volume-weighted average	6.64	6.90	(0.26)
*Oil and NGL (per bbl)*
Rocky Mountains	$32.01	$74.47	($42.46)
Midcontinent	36.90	73.79	(36.89)
Volume-weighted average	34.09	74.18	(40.09)

Questar E&P hedged or pre-sold approximately 77% of gas production in the first three months of 2009 and 2008. Hedging increased Questar E&P 2009 gas revenues by $136.4 million and 2008 gas revenues by $6.9 million. Approximately 25% of 2009 and 53% of 2008 Questar E&P oil production was hedged or pre-sold. Oil hedges increased revenues $4.6 million in 2009 and decreased revenues $7.4 million in 2008.

Questar 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. During the first quarter of 2009, Questar E&P hedged additional production through 2011. 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. However, natural gas basis-only swaps expose the Company to losses from narrowing natural gas-price basis differentials.

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 8% to $4.12 per Mcfe in 2009 versus $3.83 per Mcfe in 2008. Questar E&P production costs are summarized in the following table:

Questar Market Resources 2009 Form 10-Q


	3 Months Ended March 31,
	2009	2008	Change
	(per Mcfe)
Depreciation, depletion and amortization	$2.42	$1.82	$0.60
Lease operating expense	0.73	0.71	0.02
General and administrative expense	0.33	0.36	(0.03)
Allocated interest expense	0.31	0.26	0.05
Production taxes	0.33	0.68	(0.35)
Total Production Costs	$4.12	$3.83	$0.29

Production volume-weighted average depreciation, depletion and amortization (DD&A) expense per Mcfe increased in 2009 due to third and fourth quarter 2008 price-related negative reserve revisions, the ongoing depletion of older, lower-cost reserves and the increasing share of Questar E&P production derived from properties that are being developed in a higher-cost environment. The DD&A rate also increased due to higher costs for drilling, completion and related services, higher cost of steel casing, other tubulars and wellhead equipment during the peak of industry activity in 2008. Lease operating expense per Mcfe was higher due to increased costs of materials and consumables, increased produced-water disposal costs and increased well-workover activity. General and administrative expense per Mcfe decreased due primarily to increased production. Allocated interest expense per unit of production increased in the 2009 period primarily due to financing costs related to the 2008 acquisition of properties in northwest Louisiana. Production taxes per Mcfe decreased in the first quarter of 2009 as a result of lower natural gas and oil sales prices. The Company pays production taxes based on sales prices before the impact of hedges.

Major Questar E&P Operating Areas

Pinedale Anticline

As of March 31, 2009, Market Resources (including both Questar E&P and Wexpro) operated and had working interests in 337 producing wells on the Pinedale Anticline compared to 250 at the end of the first quarter of 2008. Of the 337 producing wells, Questar E&P has working interests in 315 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 337 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. 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 1,400 additional wells will be required to fully develop the Lance Pool on its acreage.

Uinta Basin

As of March 31, 2009, Questar E&P had an operating interest in 888 producing wells in the Uinta Basin of eastern Utah, compared to 872 at March 31, 2008. 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 250,000 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. Planned exploration and development activity for 2009 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.

Questar Market Resources 2009 Form 10-Q

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 March 31, 2009, Questar E&P had seven operated rigs drilling in the project area and operated or had working interests in 554 producing wells in northwest Louisiana compared to 463 at March 31, 2008.

Wexpro

Wexpro reported net income of $18.8 million in the first quarter of 2009 compared to $16.2 million in 2008, a 16% increase. Wexpro 2009 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 $400.1 million at March 31, 2009, an increase of $85.6 million or 27% since March 31, 2008. Wexpro produced 13.2 Bcf of cost-of-service gas in the 2009 quarter.

MIDSTREAM FIELD SERVICES – Questar Gas Management

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


	3 Months Ended March 31,
	2009	2008	Change
	(in millions)
Operating Income
REVENUES
Gathering	$36.6	$35.3	$ 1.3
Processing	18.4	33.6	(15.2)
Total Revenues	55.0	68.9	(13.9)
OPERATING EXPENSES
Operating and maintenance	19.6	24.1	(4.5)
General and administrative	3.8	5.1	(1.3)
Production and other taxes	0.9	0.3	0.6
Depreciation, depletion and amortization	10.9	6.3	4.6
Total Operating Expenses	35.2	35.8	(0.6)
Net loss from asset sales	(0.2)		(0.2)
Operating Income	$19.6	$33.1	($13.5)
Operating Statistics
Natural gas processing volumes
NGL sales (MMgal)	21.4	21.4
NGL sales price (per gal)	$0.47	$1.21	($0.74)
Fee-based processing volumes (in millions of MMBtu)
For unaffiliated customers	24.8	24.7	0.1
For affiliated customers	27.7	25.5	2.2
Total Fee-Based Processing Volumes	52.5	50.2	2.3
Fee-based processing (per MMBtu)	$0.16	$0.14	$0.02
Natural gas gathering volumes (in millions of MMBtu)
For unaffiliated customers	65.1	51.3	13.8
For affiliated customers	44.9	37.3	7.6
Total Gas Gathering Volumes	110.0	88.6	21.4
Gas gathering revenue (per MMBtu)	$0.29	$0.32	($0.03)

Questar Market Resources 2009 Form 10-Q

Gas Management, which provides gas-gathering and processing-services, reported net income of $11.4 million in the first three months of 2009 compared to $18.5 million in the same period of 2008. The decrease in net income was driven by lower gathering and processing margins and increased depreciation expense. Depreciation expense grew $4.6 million or 73% as the result of investment additions in 2008.

Total gathering margins (revenues minus direct gathering expenses) in 2009 decreased 3% to $26.2 million compared to $27.0 million in 2008. Expanding Pinedale production, new projects serving third parties in the Uinta Basin and the consolidation of Rendezvous contributed to a 27% increase in third-party volumes in 2009. Gathering volumes increased 21.4 million MMBtu, or 24% to 110.0 million MMBtu in 2009. Rendezvous, formerly an unconsolidated affiliate, was consolidated with Gas Management beginning in 2008. 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 2009 decreased 48% to $9.3 million compared to $17.8 million in 2008. Fee-based gas processing volumes were 52.5 million MMBtu in 2009, a 5% increase compared to 2008. In 2009, fee-based gas processing revenues increased 17% or $1.2 million, while the frac spread from keep-whole processing decreased 72% or $8.8 million. Approximately 93% of Gas Management’s net operating revenue (revenue minus processing plant-shrink) in 2009 was derived from fee-based contracts, up from 78% in 2008.

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

ENERGY MARKETING – Questar Energy Trading

Energy Trading net income was $5.4 million in 2009, a decrease of 33% compared to $8.1 million in 2008 as a result of lower marketing margin. Revenues from unaffiliated customers were $114.6 million in 2009 compared to $194.5 million in 2008, a 41% decrease, primarily the result of lower natural gas prices. The weighted-average natural gas sales price decreased 46% in 2009 to $3.78 per MMBtu, compared to $7.04 per MMBtu in 2008.

Consolidated Results after Operating Income

Interest expense

Interest expense rose 29% in the first three months of 2009 compared to a year ago due primarily to financing activities associated with the purchase of natural gas development properties in northwest Louisiana.

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. However, natural gas basis-only swaps expose the company to losses from narrowing natural gas-price basis differentials. The Company recognized a pre-tax net mark-to-market loss of $134.9 million on natural gas basis-only swaps in the first quarter of 2009 compared to a $13.7 million gain in the first quarter of 2008.

Income taxes

The effective combined federal and state income tax rate was 34.8% in the first three months of 2009 compared with 37.0% in the 2008 period.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

Commodity-Price Risk Management

Market Resources uses gas- and oil-price-derivatives in the normal course of business to reduce, or hedge, the risk of adverse commodity-price movements. However, these same arrangements typically limit future gains from favorable price movements. Derivative contracts are currently in place for a significant share of Questar E&P-owned gas and oil production, a portion of Energy Trading gas- and oil-marketing transactions and some of Gas Management NGL sales.

As of March 31, 2009, Market Resources held commodity-price hedging contracts covering about 252.4 million MMBtu of natural gas and 0.6 million barrels of oil and basis-only swaps on an additional 171.7 Bcf of natural gas. A year earlier the

Questar Market Resources 2009 Form 10-Q

Market Resources hedging contracts covered 353.7 million MMBtu of natural gas, 1.7 million barrels of oil and natural gas basis-only swaps on an additional 17.8 Bcf. Changes in the fair value of derivative contracts from December 31, 2008 to March 31, 2009 are presented below:


	Fixed-price	Basis-only
	Swaps	Swaps	Total
	(in millions)
Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2008	$543.6	($75.5)	$468.1
Contracts realized or otherwise settled	(112.7)	4.8	(107.9)
Change in gas and oil prices on futures markets	182.8	(128.8)	54.0
Contracts added	8.6		8.6
Contracts re-designated as fixed-price swaps	10.9	(10.9)
Net fair value of gas- and oil-derivative contracts outstanding at March 31, 2009	$633.2	($210.4)	$422.8

A table of the net fair value of gas- and oil-derivative contracts as of March 31, 2009, is shown below. About 82% of the fixed-priced swaps will settle in the next 12 months and the fair value of cash-flow hedges will be reclassified from other comprehensive income:


	Fixed-price	Basis-only
	Swaps	Swaps	Total
	(in millions)
Contracts maturing by March 31, 2010	$522.3	($58.0)	$464.3
Contracts maturing between April 1, 2010 and March 31, 2011	113.4	(88.1)	25.3
Contracts maturing between April 1, 2011 and March 31, 2012	(2.5)	(64.3)	(66.8)
Net fair value of gas- and oil-derivative contracts outstanding at March 31, 2009	$633.2	($210.4)	$422.8

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


	March 31,
	2009	2008
	(in millions)
Net fair value – asset (liability)	$422.8	($243.5)
Fair value if market prices of gas and oil and basis differentials decline by 10%	539.9	24.7
Fair value if market prices of gas and oil and basis differentials increase by 10%	305.8	(511.5)

Interest-Rate Risk Management

As of March 31, 2009, Market Resources had $850 million of fixed-rate long-term debt and $500 million of variable-rate long-term debt.

Forward-Looking Statements

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

Questar Market Resources 2009 Form 10-Q

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

the risk factors discussed in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008;

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

changes in industry trends;

changes in laws or regulations; and

other factors, most of which are beyond the Company’s control.

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

ITEM 4. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures.

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended) as of March 31, 2009. Based on such evaluation, such officers have concluded that, as of March 31, 2009, the Company’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company, including its consolidated subsidiaries, required to be included in the Company’s reports filed or submitted under the Exchange Act. The Company’s Chief Executive Officer and Chief Financial Officer also concluded that the controls and procedures were effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management including its principal executive and financial officers or persons performing similar functions as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls.

There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter ended March 31, 2009, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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., Civil No. 208CV167, 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 are therefore within “Indian Country”. EPA asserts primary CAA jurisdiction over "Indian Country" where state CAA programs do not apply. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for Gas Management’s facilities render them “major sources” of emissions for criteria and hazardous air pollutants. Categorization of the facilities as “major sources” affects the particular regulatory

Questar Market Resources 2009 Form 10-Q

program applicable to those facilities. EPA claims that Gas Management failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations for testing and reporting, among other things. Gas Management contends that its facilities have pollution controls installed that reduce their actual air emissions below major source thresholds, rendering them subject to different regulatory requirements. 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 avoided by applying Utah’s CAA program or EPA's prior practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict all reasonably possible outcomes; however, management believes the Company has accrued a reasonable loss contingency that is an immaterial amount, for the anticipated most likely outcome.

Grynberg Case

In United States ex rel. Grynberg v. Questar Corp., Civil No. 99-MD-1604, consolidated as In re Natural Gas Royalties Qui Tam Litigation, Consolidated Case MDL No. 1293 (D. Wyo.), Jack Grynberg filed claims against Questar under the federal False Claims Act that were substantially similar to cases filed against other natural gas companies. The cases were consolidated for discovery and pre-trial motions in Wyoming’s federal district court. The cases involve allegations of industry-wide mismeasurement of natural gas quantities on which royalty payments are due the federal government. By order dated October 20, 2006, the district court dismissed all of Grynberg’s claims against all the defendants for lack of jurisdiction. The judge found that Grynberg was not the “original source” and therefore could not bring the action. Grynberg appealed the case to the U.S. Tenth Circuit Court of Appeals. On March 17, 2009, the Court of Appeals affirmed the lower court decision to dismiss the case.

ITEM 6. EXHIBITS.

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

Exhibit No.

Exhibits

12.

Ratio of Earnings to Fixed Charges. (Exhibit No. 12. to the Company’s Quarterly Report on Form 10-Q for quarter ended March 31, 2009.)

31.1.

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

31.2.

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

32.

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

SIGNATURES

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

QUESTAR MARKET RESOURCES, INC.

(Registrant)

May 8, 2009

/s/C. B. Stanley

C. B. Stanley

President and Chief Executive Officer

May 8, 2009

/s/S. E. Parks

S. E. Parks

Vice President and Chief Financial Officer

Questar Market Resources 2009 Form 10-Q

Exhibit No.

Exhibits

12.

Ratio of Earnings to Fixed Charges. (Exhibit No. 12. to the Company’s Quarterly Report on Form 10-Q for quarter ended March 31, 2009.)

31.1.

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

31.2.

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

32.

Questar Market Resources 2009 Form 10-Q