UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Year Ended December 31, 2009

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 No.)	(I.R.S. Employer Identification No.)

180 East 100 South, P.O. Box 45601, Salt Lake City, Utah 84145-0601

(Address of principal executive offices)

Registrant's telephone number:  (801) 324-2600

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to Section 12(g) of the Act:

Common stock, $1.00 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  [  ]

No  [X]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  [  ] No  [X]

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [  ]

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 definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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]

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter. (June 30, 2009):  $0.

At February 28, 2010, there were 4,309,427 shares of the registrant's $1.00 par value common stock outstanding. All shares are owned by Questar Corporation.

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

TABLE OF CONTENTS

Page No.

Where You Can Find More Information

3

Forward-Looking Statements

3

Glossary of Commonly Used Terms

4

PART I

Item 1.

BUSINESS

Nature of Business

6

Exploration and Production – Questar E&P and Wexpro

7

Midstream Field Services – Questar Gas Management

8

Energy Marketing – Questar Energy Trading

8

Employees

9

Item 1A.

RISK FACTORS

9

Item 1B.

UNRESOLVED STAFF COMMENTS

12

Item 2.

PROPERTIES

Exploration and Production – Questar E&P and Wexpro

12

Midstream Field Services – Questar Gas Management

16

Energy Marketing – Questar Energy Trading

16

Item 3.

LEGAL PROCEEDINGS

16

Item 4.

(REMOVED AND RESERVED)

17

PART II

Item 5.

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED

STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY

SECURITIES

17

Item 6.

SELECTED FINANCIAL DATA (omitted)

17

Item 7.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATION

17

Item 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT

MARKET RISK

25

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

27

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

59

Item 9A(T).

CONTROLS AND PROCEDURES

60

Item 9B.

OTHER INFORMATION

60

Questar Market Resources 2009 Form 10-K

1

PART III

Item 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

(omitted)

60

Item 11.

EXECUTIVE COMPENSATION (omitted)

60

Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND

MANAGEMENT AND RELATED STOCKHOLDER MATTERS (omitted)

60

Item 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

AND DIRECTOR INDEPENDENCE (omitted)

60

Item 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

60

PART IV

Item 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

61

SIGNATURES

63

Questar Market Resources 2009 Form 10-K

2

Where You Can Find More Information

Questar Market Resources, Inc. (Market Resources or the Company), is a wholly owned subsidiary of Questar Corporation (Questar). Both Questar and Market Resources file annual, quarterly, and current reports with the Securities and Exchange Commission (SEC). These reports and other information can be read and copied at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549-0213. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC also maintains an internet site at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including Market Resources.

Investors can also access financial and other information via Questar's Web site at www.questar.com. Questar and Market Resources make available, free of charge through the Web site copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to such reports. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC. Information contained on or connected to Questar's Web site which is not directly incorporated by reference into the Company's Annual Report on Form 10-K should not be considered part of this report or any other filing made with the SEC.

Questar's Web site also contains copies of Statements of Responsibility for various board committees, including the Finance and Audit Committee, Corporate Governance Guidelines and Questar's Business Ethics and Compliance Policy.

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

Forward-Looking Statements

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

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

·

the risk factors discussed in Part I, Item 1A of this Annual Report;

·

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 Annual 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.

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Glossary of Commonly Used Terms

B   Billion.

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

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

basis-only swap   A derivative that "swaps" the basis (defined above) between two sales points from a floating price to a fixed price for a specified commodity volume over a specified time period. Typically used to fix the price relationship between a geographic sales point and a NYMEX reference price.

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

cash flow hedge   A derivative instrument that complies with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 815 and is used to reduce the exposure to variability in cash flows from the forecasted physical sale of gas and oil production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted physical sale.

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

cfe   Cubic feet of natural gas equivalents.

developed reserves   Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. See 17 C.F.R. Section 210.4-10(a)(6).

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

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

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

dthe   Decatherms of natural gas equivalents.

equity production   Production at the wellhead attributed to Questar ownership.

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

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

gal   U.S. gallon.

gas   All references to "gas" in this report refer to natural gas.

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

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

M   Thousand.

MM   Million.

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

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

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

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

NYMEX   The New York Mercantile Exchange.

proved reserves   Those quantities of natural gas, oil, condensate and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. See 17 C.F.R. Section 210.4-10(a)(22).

reserves   Estimated remaining quantities of natural gas, oil and related substances anticipated to be economically producible by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce. See 17 C.F.R. Section 210.4-10(a)(26).

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

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

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

undeveloped reserves   Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. See 17 C.F.R. Section 210.4-10(a)(31).

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

workover   Operations on a producing well to restore or increase production.

Questar Market Resources 2009 Form 10-K

5

FORM 10-K

ANNUAL REPORT, 2009

PART I

ITEM 1.  BUSINESS.

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.

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.

 

The corporate-organization structure and major subsidiaries are summarized below:

See Note 14 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for financial information by line of business including, but not limited to, revenues from unaffiliated customers, operating income and identifiable assets. A discussion of each of the Company's lines of business follows.

Questar Market Resources 2009 Form 10-K

6

EXPLORATION AND PRODUCTION – Questar E&P and Wexpro

General: Market Resources' exploration and production business is conducted through Questar E&P and Wexpro. Questar E&P and Wexpro generated approximately 82% of the Company's operating income in 2009. Questar E&P operates in two core areas - the Rocky Mountain region of Wyoming, Utah, Colorado and North Dakota and the Midcontinent region of Oklahoma, Texas and Louisiana. Questar E&P has a large inventory of identified development drilling locations, primarily on the Pinedale Anticline in western Wyoming and in northwestern Louisiana. Questar E&P continues to conduct exploratory drilling to determine the commerciality of its inventory of undeveloped leaseholds. Questar E&P seeks to acquire, develop and produce natural gas and oil from so-called "resource plays" in its core areas. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations in tight sand, shale and coal reservoirs. Since the existence and distribution of hydrocarbons in resource plays is well understood, development of these accumulations has lower exploration risk than conventional discrete hydrocarbon accumulations. Resource plays typically require many wells, drilled at high density, to fully develop and produce. Development of resource play accumulations requires expertise in drilling large numbers of complex, highly deviated or horizontal development wells to depths in excess of 13,000 feet and application of advanced well stimulation techniques including hydraulic fracture stimulation to achieve economic production. Questar E&P seeks to maintain geographical and geological diversity with its two core areas. Questar E&P has in the past and may in the future pursue acquisition of producing properties through the purchase of assets or corporate entities to expand its presence in its core areas or create a new core area.

Questar E&P reported 2,746.9 Bcfe of estimated proved reserves as of December 31, 2009. Approximately 60% of Questar E&P's proved reserves, or 1,646.4 Bcfe, were located in the Rocky Mountain region of the United States, while the remaining 40%, or 1,100.5 Bcfe, were located in the Midcontinent region. Approximately 1,342.8 Bcfe of the proved reserves reported by Questar E&P at year-end 2009 were developed, while 1,404.1 Bcfe were categorized as proved undeveloped. Natural gas comprised about 92% of Questar E&P's total proved reserves at year-end 2009. The SEC amended its definitions of oil and natural gas reserves effective December 31, 2009. Key revisions impacting the Company include a change in the pricing used in estimating reserves to a 12-month average of the first-day-of-the month prices, reserve category definitional changes and allowing the application of reliable technologies in determining proved reserves. See Item 2 of Part I and Note 16 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company's proved reserves.

Wexpro manages, develops and produces cost of service reserves for gas utility affiliate Questar Gas under the terms of the Wexpro Agreement, a long-standing comprehensive agreement with the states of Utah and Wyoming. 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. The term of the Wexpro Agreement coincides with the productive life of the gas and oil properties covered therein. Wexpro's investment base totaled $431.9 million at December 31, 2009. See Note 10 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Wexpro Agreement.

Wexpro delivers natural gas production to Questar Gas at a price equal to Wexpro's cost-of-service. Cost-of-service gas satisfied 51% of Questar Gas supply requirements during 2009. Wexpro sells crude-oil production from oil-producing properties at market prices. Wexpro recovers operating expenses and a return on investment from crude-oil sales. Any residual operating income after recovery of operating expenses and return on investment is shared with Questar Gas receiving 54% and Wexpro retaining 46%.

Wexpro's cost of service operations are contractually limited to a finite set of properties set forth in the Wexpro Agreement. Advances in technology (increased density drilling and multi-stage hydraulic fracture stimulation) have identified significant unexploited potential on many of the subject properties. Wexpro has identified over $1 billion of additional drilling opportunities that could support high single-digit to low double-digit growth in revenues and net income over the next five to ten years while delivering cost-of-service natural gas supplies to Questar Gas at prices competitive with alternative sources.

Competition and Customers: Questar E&P faces competition in every part of its business, including the acquisition of producing properties and leasehold acreage, the marketing of gas and oil, and obtaining goods, services and labor. Its longer-term growth strategy depends, in part, on its ability to purchase reasonably-priced reserves and develop them in a low-cost and efficient manner.

Questar E&P, both directly and through Energy Trading, sells natural gas production to a variety of customers, including gas-marketing firms, industrial users and local-distribution companies. However, Questar E&P and Energy Trading do not sell natural gas to Questar Gas. Questar E&P regularly evaluates counterparty credit and may require financial guarantees from parties that fail to meet its credit criteria.

In 2009, 93% of Wexpro's revenues were from affiliated companies, primarily Questar Gas.

Regulation: Questar E&P and Wexpro operations are subject to various government controls and regulation at the federal, state and local levels. Questar E&P must obtain permits to drill and produce; maintain bonding requirements to drill and operate wells;

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submit and implement spill-prevention plans; and file notices relating to the presence, use, and release of specified contaminants incidental to gas and oil production. Questar E&P is also subject to various conservation matters, including the regulation of the size of drilling and spacing units, the number of wells that may be drilled in a unit and the unitization or pooling of gas and oil properties. Wexpro gas- and oil-development and production activities are subject to the same type of regulation as Questar E&P. In addition, the Utah Division of Public Utilities has oversight responsibility and retains an outside reservoir-engineering consultant and a financial auditor to assess the prudence of Wexpro's activities.

Most Questar E&P leasehold acreage in the Rocky Mountain area is held under leases granted by the federal government and administered by federal agencies, principally the Bureau of Land Management (BLM). Current federal regulations restrict activities during certain times of the year on significant portions of Questar E&P leasehold due to wildlife activity and/or habitat. Questar E&P has worked with federal and state officials in Wyoming to obtain authorization for limited winter-drilling activities on the Pinedale Anticline and has developed measures, such as drilling multiple wells from a single pad location, to minimize the impact of its activities on wildlife and wildlife habitat. Various wildlife species inhabit Questar E&P leaseholds at Pinedale and in other areas. The presence of wildlife, including species that are protected under the federal Endangered Species Act could limit access to leases held by Questar E&P on public lands.

In September 2008, the BLM issued a Record of Decision (ROD) on the Final Supplemental Environmental Impact Statement (FSEIS) for long-term development of natural gas resources in the Pinedale Anticline Project Area (PAPA). Under the ROD, Questar E&P and Wexpro are allowed to drill and complete wells year-round in one of five Concentrated Development Areas defined in the PAPA. The ROD contains additional requirements and restrictions on development of the PAPA.

MIDSTREAM FIELD SERVICES – Questar Gas Management

General: Gas Management generated approximately 16% of the Company's operating income in 2009. Gas Management owns 78% of Rendezvous Gas Services, LLC, (Rendezvous), a partnership that operates gas-gathering facilities in western Wyoming. Rendezvous gathers natural gas for Pinedale Anticline and Jonah field producers for delivery to various interstate pipelines. Gas Management also owns 38% of Uintah Basin Field Services, LLC (Field Services) and 50% of Three Rivers Gathering, LLC (Three Rivers) partnerships that operate gas-gathering facilities in eastern Utah. The FERC-regulated Rendezvous Pipeline Co., LLC (Rendezvous Pipeline), a wholly owned subsidiary of Gas Management, operates a 21-mile 20-inch-diameter pipeline between Gas Management's Blacks Fork gas-processing plant and the Muddy Creek compressor station owned by Kern River Gas Transmission Co. (Kern River Pipeline).

Fee-based gathering and processing revenues were 81% of Gas Management's net operating revenues (revenues less plant shrink) during 2009. Approximately 42% of Gas Management's 2009 net gas-processing revenues (processing revenues less plant shrink) were derived from fee-based processing agreements. The remaining revenues were derived from keep-whole processing agreements. A keep-whole contract exposes Gas Management to frac-spread risk while a fee-based contract eliminates commodity price exposure. To further reduce volatility associated with keep-whole contracts, Gas Management may enter into forward-sales contracts for NGL or hedge NGL prices and equivalent gas volumes with the intent to lock in a processing margin. Under a contract with Questar Gas, Gas Management also gathers cost-of-service volumes produced from properties operated by Wexpro.

In 2009, 10% of Gas Management's revenues were from affiliated companies, primarily Questar Gas.

Competition and Customers: Gas Management provides natural gas-gathering and processing services to affiliates and third-party producers who have proved and/or producing gas fields in the Rocky Mountain region. Most of Gas Management's gas-gathering and processing services are provided under long-term agreements.

ENERGY MARKETING – Questar Energy Trading

General: Energy Trading markets natural gas, oil and NGL and generated approximately 2% of the Company's operating income in 2009. It includes Questar E&P production and gas volumes purchased from third parties to build a flexible and reliable portfolio. As a wholesale marketing entity, Energy Trading concentrates on markets in the Rocky Mountains, Pacific Northwest and Midcontinent that are either close to affiliate reserves and production or accessible by major pipelines. Energy Trading contracts for firm-transportation capacity on pipelines and firm-storage capacity at Clay Basin, a large baseload-storage facility owned by affiliate Questar Pipeline. Energy Trading, through its subsidiary Clear Creek Storage Company, LLC, operates an underground gas-storage reservoir in southwestern Wyoming. Energy Trading uses owned and leased-storage capacity together with firm-transportation capacity to take advantage of price differentials and arbitrage opportunities.

Competition and Customers: Energy Trading sells Questar E&P crude-oil production to refiners, remarketers and other companies, including some with pipeline facilities near Company producing properties. In the event pipeline facilities are not available, Energy Trading transports crude oil by truck or rail to storage, refining or pipeline facilities. Energy Trading uses derivative instruments to manage commodity price risk. Energy Trading primarily uses fixed-price swaps to secure a known price

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for a specific volume of production. Energy Trading does not engage in speculative hedging transactions. See Item 7A and Notes 1 and 6 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for additional information relating to hedging activities.

Employees

At December 31, 2009, Market Resources had 905 employees compared with 907 a year earlier.

ITEM 1A.  RISK FACTORS.

Investors should read carefully the following factors as well as the cautionary statements referred to in "Forward-Looking Statements" herein. If any of the risks and uncertainties described below or elsewhere in this Annual Report actually occur, the Company's business, financial condition or results of operations could be materially adversely affected.

Risks Inherent in the Company's Business

The future prices for natural gas, oil and NGL are unpredictable. Historically natural gas, oil and NGL prices have been volatile and will likely continue to be volatile in the future. U.S. natural gas prices in particular are significantly influenced by weather. Any significant or extended decline in commodity prices would impact the Company's future financial condition, revenue, operating result, cash flow, return on invested capital, and rate of growth. Because approximately 92% of Market Resources' proved reserves at December 31, 2009, were natural gas, the Company's revenue, margin, cash flow, net income and return on invested capital are substantially more sensitive to changes in natural gas prices than to changes in oil prices.

Market Resources cannot predict the future price of natural gas, oil and NGL because of factors beyond its control, including but not limited to:

•

changes in domestic and foreign supply of natural gas, oil and NGL;

•

changes in local, regional, national and global demand for natural gas, oil, and NGL;

•

regional price differences resulting from available pipeline transportation capacity or local demand;

•

the level of imports of, and the price of, foreign natural gas, oil and NGL;

•

domestic and global economic conditions;

•

domestic political developments;

•

weather conditions;

•

domestic and foreign government regulations and taxes;

•

technological advances affecting energy consumption and energy supply;

•

political instability or armed conflict in oil and natural gas producing regions;

•

conservation efforts;

•

the price, availability and acceptance of alternative fuels;

•

storage levels of natural gas, oil, and NGL; and

•

the quality of gas and oil produced.

The Company may not be able to economically find and develop new reserves. The Company's profitability depends not only on prevailing prices for natural gas, oil and NGL, but also its ability to find, develop and acquire gas and oil reserves that are economically recoverable. Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics. Because of the high-rate production decline profile of several of the Company's producing areas, substantial capital expenditures are required to find, develop and acquire gas and oil reserves to replace those depleted by production.

Gas and oil reserve estimates are imprecise and subject to revision. Questar E&P's proved natural gas and oil reserve estimates are prepared annually by independent reservoir-engineering consultants. Gas and oil reserve estimates are subject to numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and timing of development expenditures. The accuracy of these estimates depends on the quality of available data and on engineering and geological interpretation and judgment. Reserve estimates are imprecise and will change as additional information becomes available. Estimates of economically recoverable reserves and future net cash flows prepared by different engineers, or by the same engineers at different times, may vary significantly. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition, the estimation process also involves economic assumptions relating to commodity prices, production costs, severance and other taxes, capital expenditures and remediation costs. Actual results most likely will vary from the estimates. Any significant variance from these assumptions could affect the recoverable quantities of reserves attributable to any particular properties, the classifications of reserves, the estimated future net cash flows from proved reserves and the present value of those reserves.

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Investors should not assume that Questar E&P's presentation of the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves in this Annual Report is the current market value of the estimated natural gas and oil reserves. In accordance with generally accepted accounting principles, the estimated discounted future net cash flows from Questar E&P's proved reserves is based on the first-of-the-month 12-month average prices and current costs on the date of the estimate, holding the prices and costs constant throughout the life of the properties and using a discount factor of 10 percent a year. Actual future prices and costs may differ materially from those used in the current estimate, and future determinations of the standardized measure of discounted future net cash flows using similarly determined prices and costs may be significantly different from the current estimate.

Shortages of oilfield equipment, services and qualified personnel could impact results of operations. The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. There have also been regional shortages of drilling rigs and other equipment, as demand for specialized rigs and equipment has increased along with the number of wells being drilled. These factors also cause increases in costs for equipment, services and personnel. These cost increases could impact profit margin, cash flow and operating results or restrict the ability to drill wells and conduct operations, especially during periods of lower natural gas and oil prices.

Operations involve numerous risks that might result in accidents and other operating risks and costs. Drilling is a high-risk activity. Operating risks include: fire, explosions and blow-outs; unexpected drilling conditions such as abnormally pressured formations; abandonment costs; pipe, cement or casing failures; environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids (including groundwater contamination). The Company could incur substantial losses as a result of injury or loss of life; pollution or other environmental damage; damage to or destruction of property and equipment; regulatory investigation; fines or curtailment of operations; or attorney's fees and other expenses incurred in the prosecution or defense of litigation.

There are also inherent operating risks and hazards in the Company's gas and oil production, gas gathering and gas processing that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution and impairment of operations.

As is customary in the gas and oil industry, the Company maintains insurance against some, but not all, of these potential risks and losses. Market Resources cannot assure that insurance will be adequate to cover these losses or liabilities. Losses and liabilities arising from uninsured or underinsured events could have a material adverse effect on the Company's financial condition and operations.

Disruption of, capacity constraints in, or proximity to pipeline systems could impact results of operations. Questar E&P transports gas to market by utilizing pipelines owned by others. If pipelines do not exist near producing wells, if pipeline capacity is limited or if pipeline capacity is unexpectedly disrupted, gas sales could be reduced or shut in, reducing profitability. If pipeline quality tariffs change, the Company might be required to install additional processing equipment which could increase costs.

Market Resources is dependent on bank credit facilities and continued access to capital markets to successfully execute its operating strategies. In addition to long-term notes and its revolving credit facility, Market Resources also relies on Questar's access to short-term commercial paper markets to provide financing for certain projects. The availability and cost of these credit sources is cyclical, and these capital sources may not remain available or the Company may not be able to obtain money at a reasonable cost in the future. Liquidity in the global-credit markets has severely contracted, making terms for certain financings less attractive, and in certain cases, resulted in the unavailability of certain types of financing. Loans under Market Resources' revolving-credit facility are floating-rate debt. The interest rates on these loans are tied to debt credit ratings of Market Resources and its subsidiaries published by Standard & Poor's and Moody's. A downgrade of the Company's credit ratings could increase the interest cost of debt and decrease future availability of money from banks and other sources. While management believes it is important to maintain investment grade credit ratings to conduct the Company's businesses, the Company may not be able to keep investment grade ratings.

Risks Related to Strategy

Market Resources uses derivative instruments to manage exposure to uncertain prices. Market Resources uses commodity-price derivative instruments to reduce, or hedge, exposure to volatile natural gas, oil, and NGL prices and to protect cash flow, returns on capital, net income and credit ratings from downward commodity price movements. To the extent the Company hedges commodity price exposure, it forgoes the benefits of commodity price increases. Market Resources' Wexpro subsidiary generates revenues that are not significantly sensitive to short-term fluctuations in commodity prices.

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Market Resources enters into commodity-price derivative arrangements with creditworthy counterparties (banks and energy-trading firms) that do not require collateral deposits. The amount of credit available may vary depending on the credit ratings assigned to the Company's debt securities. Market Resources is exposed to the risk of counterparties not performing.

Market Resources may be subject to risks in connection with acquisitions. The acquisition of gas and oil properties requires the assessment of recoverable reserves; future gas and oil sales prices and basis differentials; operating costs; and potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain. In connection with these assessments, the Company performs a review of the subject properties and pursues contractual protection and indemnification generally consistent with industry practices.

Risks Related to Regulation

Market Resources is subject to complex regulations on many levels. The Company is subject to federal, state and local environmental, health and safety laws and regulations. Environmental laws and regulations are complex, change frequently and tend to become more onerous over time. In addition to the costs of compliance, substantial costs may be incurred to take corrective actions at both owned and previously-owned facilities. Accidental spills and leaks requiring cleanup may occur in the ordinary course of business. As standards change, the Company may incur significant costs in cases where past operations followed practices that were considered acceptable at the time but now require remedial work to meet current standards. Failure to comply with these laws and regulations may result in fines, significant costs for remedial activities, or injunctions.

Market Resources must comply with numerous and complex federal and state regulations governing activities on federal and state lands, notably the National Environmental Policy Act, the Endangered Species Act, the Clean Air Act, and the National Historic Preservation Act and similar state laws. The United States Fish and Wildlife Service may designate critical habitat areas for certain listed threatened or endangered species. A critical habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. The listing of certain species, such as the sage grouse, as threatened and endangered, could have a material impact on the Company's operations in areas where such species are found. The Clean Water Act and similar state laws regulate discharges of storm water, wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and other costs and damages. These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil.

Federal and state agencies frequently impose conditions on the Company's activities. These restrictions have become more stringent over time and can limit or prevent exploration and production on the Company's leasehold. Certain environmental groups oppose drilling on some of Market Resources' federal and state leases. These groups sometimes sue federal and state agencies for alleged procedural violations in an attempt to stop, limit or delay natural gas and oil development on public lands.

All wells drilled in tight gas sand and shale reservoirs require hydraulic fracture stimulation to achieve economic production rates and recoverable reserves. A significant portion of the Company's current and future production and reserve potential is derived from reservoirs that require hydraulic fracture stimulation to be commercially viable. Currently, all well construction activities, including hydraulic fracture stimulation, are regulated by state agencies that review and approve all aspects of gas and oil well design and operation. New environmental initiatives, proposed federal and state legislation and rulemaking pertaining to hydraulic fracture stimulation could include additional permitting and reporting requirements and potential restrictions on the use of hydraulic fracture stimulation that could materially affect the Company's ability to develop and produce gas and oil reserves.

In addition, the Company is subject to federal and state hazard communications and community right-to-know statutes and regulations such as the Emergency Planning and Community Right-to-Know Act that require certain record keeping and reporting of the use and release of hazardous substances.

Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations include such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. One or more of these factors may increase the Company's costs of doing business on Native American tribal lands and have an impact on the viability of its gas and oil exploration, production, gathering, processing and transportation operations on such lands.

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Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of the Company's exploration and production and midstream field services operations. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, needed permits may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict Market Resources' ability to conduct its operations or to do so profitably.

Market Resources may be exposed to certain regulatory and financial risks related to climate change. Federal and state courts and administrative agencies are considering the scope and scale of climate-change regulation under various laws pertaining to the environment, energy use and development, and greenhouse gas emissions. Market Resources' ability to access and develop new natural gas reserves may be restricted by climate-change regulation. There are bills pending in Congress that would regulate greenhouse gas emissions through a cap-and-trade system under which emitters would be required to buy allowances for offsets of emissions of greenhouse gases. The Environmental Protection Agency (EPA) has adopted final regulations for the measurement and reporting of greenhouse gases emitted from certain large facilities (25,000 tons/year of CO₂ equivalent) beginning with operations in 2010. The first report is to be filed with the EPA by March 31, 2011. In addition, several of the states in which Market Resources operates are considering various greenhouse gas registration and reduction programs. Carbon dioxide regulation could increase the price of natural gas, restrict access to or the use of natural gas, and/or reduce natural gas demand. Federal, state and local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for natural gas. While future climate-change regulation is likely, it is too early to predict how this regulation will affect Market Resources' business, operations or financial results. It is uncertain whether Market and properties, located in the Rocky Mountain and Midcontinent regions of the United States, are exposed to possible physical risks, such as severe weather patterns, due to climate change as a result of man-made greenhouse gases. However, management does not believe such physical risks are reasonably likely to have a material effect on the Company's financial condition or results of operations.

Other Risks

General economic and other conditions impact Market Resources' results. Market Resources' results may also be negatively affected by: changes in global economic conditions; changes in regulation; availability and economic viability of gas and oil properties for sale or exploration; creditworthiness of counterparties; rate of inflation and interest rates; assumptions used in business combinations; weather and natural disasters; changes in customers' credit ratings; competition from other forms of energy, other pipelines and storage facilities; effects of accounting policies issued periodically by accounting standard-setting bodies; terrorist attacks or acts of war; changes in business or financial condition; changes in credit ratings; and availability of financing for Market Resources.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2.  PROPERTIES.

EXPLORATION AND PRODUCTION

Reserves – Questar E&P

Questar E&P's reserve estimates are prepared by Ryder Scott Company, L.P., independent reservoir-engineering consultants. The estimates of proved reserves at December 31, 2009, were made in accordance with amended reserves definitions included in the SEC's rules for the Modernization of Oil and Gas Reporting. The most significant amendments affecting the Company include, allowing the use of reliable technologies to estimate and categorize reserves and using the arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period (unless contractual arrangements designate the price) to be used to calculate economic producibility of reserves and the discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to Proved Reserves. Refer to Note 16 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for additional information regarding estimates of proved reserves and the preparation of such estimates.

Questar E&P does not have any long-term supply contracts with foreign governments or reserves of equity investees or reserves of subsidiaries with a significant minority interest. At December 31, 2009, approximately 90% of Questar E&P's estimated proved reserves were Company operated. All reported reserves are located in the United States. Questar E&P's estimated reserves are summarized as follows:

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	December 31, 2009
	Natural Gas	Oil and NGL	Natural Gas Equivalents
	(Bcf)	(MMbbl)	(Bcfe)
Proved developed reserves	1,178.7	27.4	1,342.8
Proved undeveloped reserves	1,346.3	9.6	1,404.1
Total proved reserves	2,525.0	37.0	2,746.9

Questar E&P's reserve statistics for the years ended December 31, 2007 through 2009, are summarized below:

Year	Year End Reserves (Bcfe)	Proved Gas and Oil Reserves Annual Production (Bcfe)	Reserve Life Index (a) (Years)
2007	1,867.6	140.2	13.3
2008	2,218.1	171.4	12.9
2009	2,746.9	189.5	14.5

^(a)Reserve life index is calculated by dividing year-end proved reserves by production for such year.

Questar E&P proved reserves by major operating areas at December 31, 2009 and 2008 follow:

	2009		2008
	(Bcfe)	(% of total)	(Bcfe)	(% of total)
Midcontinent	1,100.5	40	630.8	28
Pinedale Anticline	1,300.7	47	1,164.9	53
Uinta Basin	197.7	7	258.8	12
Rockies Legacy	148.0	6	163.6	7
Total Questar E&P	2,746.9	100	2,218.1	100

Reserves – Cost-of-Service

Wexpro manages, develops and produces cost-of-service reserves for Questar Gas under the terms of the Wexpro Agreement. The following table sets forth estimated cost-of-service natural gas and oil reserves. The estimates of cost-of-service proved reserves were made by Wexpro's reservoir engineers as of December 31, 2009. All reported reserves are located in the United States.

	December 31, 2009
	Natural Gas	Oil and NGL	Natural Gas Equivalents
	(Bcf)	(MMbbl)	(Bcfe)
Proved developed reserves	477.1	3.1	495.5
Proved undeveloped reserves	172.3	1.4	180.8
Total proved reserves	649.4	4.5	676.3

Wexpro delivers natural gas production to Questar Gas at a price equal to Wexpro's cost-of-service. Wexpro sells crude-oil production from oil-producing properties at market prices. Wexpro recovers operating expenses and a return on investment from crude-oil sales. Any residual operating income after recovery of operating expenses and a return on investment is shared with Questar Gas receiving 54% and Wexpro retaining 46%. Therefore, SEC guidelines with respect to standard economic assumptions do not apply to Wexpro. SEC guidelines provide for such exceptions. Accordingly, Wexpro reservoir engineers used a minimum producing rate or maximum well-life limit to determine the ultimate quantity of reserves attributable to each well.

Refer to Note 16 of the consolidated financial statements included in Item 8 of Part II of this Annual Report for additional information pertaining to both Questar E&P proved reserves and the Company's cost-of-service reserves as of the end of each of the last three years.

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In addition to this filing, Questar E&P and Wexpro will each file reserves estimates as of December 31, 2009, with the Energy Information Administration of the Department of Energy on Form EIA-23. Although the companies use the same technical and economic assumptions when they prepare the EIA-23, they are obligated to report reserves for all wells they operate, not for all wells in which they have an interest, and to include the reserves attributable to other owners in such wells.

Production

The following table sets forth the net production volumes, the average sales prices per Mcf of natural gas, per bbl of oil and NGL produced, and the production costs per Mcfe for the years ended December 31, 2009, 2008 and 2007.

	Year Ended December 31,
	2009	2008	2007
Questar E&P
Volumes produced and sold
Natural gas (Bcf)	168.7	151.9	121.9
Oil and NGL (MMbbl)	3.5	3.3	3.0
Total production (Bcfe)	189.5	171.4	140.2
Average realized price, net to the well (including hedges)
Natural gas (Bcf)	$  6.54	$  7.56	$  6.45
Oil and NGL (MMbbl)	45.91	72.96	53.99
Lifting costs (per Mcfe)
Lease operating expense	$  0.67	$  0.73	$  0.63
Production taxes	0.31	0.61	0.43
Total lifting costs	$  0.98	$  1.34	$  1.06
Cost-of-Service
Volumes produced
Natural gas (Bcf)	48.2	46.1	34.9
Oil and NGL (MMbbl)	0.4	0.4	0.4
Total production (Bcfe)	50.7	48.6	37.4

Productive Wells

The following table summarizes the Company's productive wells (including cost-of-service wells) as of December 31, 2009. All wells are located in the United States.

	Gas	Oil	Total
Gross	5,739	1,070	6,809
Net	2,672	500	3,172

Although many wells produce both gas and oil, a well is categorized as either a gas or an oil well based upon the ratio of gas to oil produced. Each gross well completed in more than one producing zone is counted as a single well. At the end of 2009, the Company had 161 gross wells with multiple completions.

The Company also holds numerous overriding-royalty interests in gas and oil wells, a portion of which are convertible to working interests after recovery of certain costs by third parties. After converting to working interests, these overriding-royalty interests will be included in the gross and net-well count.

Leasehold Acres

The following table summarizes developed and undeveloped-leasehold acreage in which the Company owns a working interest as of December 31, 2009. "Undeveloped Acreage" includes leasehold interests that already may have been classified as containing proved undeveloped reserves and unleased mineral-interest acreage owned by the Company. Excluded from the table is acreage in which the Company's interest is limited to royalty, overriding-royalty and other similar interests. All leasehold acres are located in the United States.

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	Developed Acres(1)		Undeveloped Acres(2)		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Arkansas	32,602	10,306	4,876	3,452	37,478	13,758
Colorado	150,320	102,922	165,175	73,725	315,495	176,647
Kansas	29,822	12,922	52,459	17,245	82,281	30,167
Louisiana	48,996	35,650	37,460	35,879	86,456	71,529
Montana	15,449	7,884	306,779	52,849	322,228	60,733
New Mexico	97,149	70,886	32,939	12,618	130,088	83,504
North Dakota	8,232	1,926	237,341	96,720	245,573	98,646
Oklahoma	1,575,938	289,311	159,330	91,763	1,735,268	381,074
South Dakota	-	-	204,398	107,151	204,398	107,151
Texas	134,061	46,404	49,462	45,078	183,523	91,482
Utah	173,266	130,776	234,854	147,908	408,120	278,684
Wyoming	291,866	184,227	311,593	207,715	603,459	391,942
Other	5,153	2,534	157,886	42,516	163,039	45,050
Total	2,562,854	895,748	1,954,552	934,619	4,517,406	1,830,367

⁽¹⁾Developed acreage is acreage assigned to productive wells.

⁽²⁾Undeveloped acreage is leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

A portion of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing leases are renewed or production has been obtained from the acreage subject to the lease prior to that date. Leases held by production remain in effect until production ceases. The following table sets forth the gross and net acres subject to leases summarized in the preceding table that will expire during the periods indicated:

Leaseholds Expiring	Undeveloped Acres Expiring
	Gross	Net
12 months ending December 31,
2010	90,964	53,174
2011	115,254	78,050
2012	51,211	33,843
2013	45,819	31,909
2014 and later	177,948	160,829

Drilling Activity

The following table summarizes the number of development and exploratory wells drilled by Market Resources, including the cost-of-service wells drilled by Wexpro, during the years indicated.

	Year Ended December 31,
	Productive			Dry
	2009	2008	2007	2009	2008	2007
Net Wells Completed
Exploratory	3.7	2.3	0.3		0.9	0.4
Development	189.9	257.8	199.6	4.0	6.2	2.5

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Gross Wells Completed
Exploratory	12	10	2		2	1
Development	304	490	426	5	13	11

MIDSTREAM FIELD SERVICES – Questar Gas Management

Gas Management owns 1,620 miles of gathering lines in Utah, Wyoming, and Colorado. Rendezvous Pipeline owns a 21-mile 20-inch-diameter line between Gas Management's Blacks Fork gas-processing plant and Kern River Pipeline's Muddy Creek compressor station that can deliver up to 300 MMcf of natural gas per day to markets in California and Nevada served by the Kern River Pipeline. In conjunction with these gathering facilities, Gas Management owns compression facilities, field-dehydration and measuring systems. Rendezvous owns an additional 329 miles of gathering lines and associated field equipment, Field Services owns 76 miles of gathering lines and associated field equipment and Three Rivers owns 57 miles of gathering lines. Gas Management owns processing plants that have an aggregate capacity of 654 MMcf of unprocessed natural gas per day.

ENERGY MARKETING – Questar Energy Trading

Energy Trading, through its wholly owned subsidiary Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir in southwestern Wyoming.

ITEM 3.  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 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 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.

On July 10, 2009, Questar E&P filed a petition with the U.S. Tenth Circuit Court of Appeals challenging an administrative compliance order dated May 12, 2009, (Order) issued by the EPA which asserts that Questar E&P's Flat Rock 14P Well and associated equipment is a major source of emissions of hazardous air pollutants and that its operation fails to comply with certain regulations of the CAA. The Order required immediate compliance and threatened substantial penalties for failure to do so. Questar E&P denies that the drilling and operation of the 14P Well and associated equipment violates any provision of the CAA and intends to vigorously defend against this Order.

In October 2009, Questar E&P received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from further discharge of dredged and/or fill material into wetlands of the United States at three well sites without a permit under the Clean Water Act (CWA). The order specifically references prior construction activities at the sites located in Caddo and Red River Parishes, Louisiana. EPA Region 6 has now assumed lead responsibility for enforcement of the pending order and any

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possible future orders for the removal of unauthorized fills and/or civil penalties under Section 309 of the CWA. The Company is working with the COE and EPA to resolve the matter.

ITEM 4.  (REMOVED AND RESERVED).

PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

All of the Company's outstanding shares of common stock, $1.00 par value, are owned by Questar. Information concerning the dividends paid on such stock and the ability to pay dividends is reported in the Statements of Consolidated Shareholder's Equity and the notes accompanying the consolidated financial statements included in Item 8 of Part II of this Annual Report.

ITEM 6.  SELECTED FINANCIAL DATA.

The Company, as a wholly owned subsidiary of a reporting company under the Act, is entitled to omit the information in this Item.

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

SUMMARY

Market Resources' net income decreased 50% in 2009 compared with 2008 due to lower realized natural gas, crude oil and NGL prices and lower processing margins. Net income increased 39% in 2008 compared to 2007 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
	2009	2008	2007	2009 vs. 2008	2008 vs. 2007
	(in millions)
Exploration and Production
Questar E&P	$134.9	$408.0	$285.5	($273.1)	$122.5
Wexpro	80.7	73.9	59.2	6.8	14.7
Midstream Field Services – Gas Management	69.4	81.5	55.3	(12.1)	26.2
Energy Marketing – Energy Trading, and other	8.5	22.1	20.8	(13.6)	1.3
Net income attributable to Market Resources	$293.5	$585.5	$420.8	($292.0)	$164.7

RESULTS OF OPERATIONS

EXPLORATION AND PRODUCTION

Questar E&P

Questar E&P reported net income of $134.9 million in 2009, down 67% from $408.0 million in 2008 and $285.5 million in 2007. Lower realized natural gas, crude oil and NGL prices and an 11% increase in 2009 average production costs more than offset an 11% increase in 2009 production. Unrealized mark-to-market losses on natural gas basis-only hedges decreased pre-tax income $164.0 million in 2009 compared to a net pre-tax loss of $79.2 million a year-earlier. Net gains from sales of assets at Questar E&P increased pre-tax income $1.6 million in 2009 compared to a net pre-tax gain of $60.4 million in the year-earlier period. Following is a summary of Questar E&P financial and operating results:

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	Year Ended December 31,			Change
	2009	2008	2007	2009 vs. 2008	2008 vs. 2007
	(in millions)
Operating Income
REVENUES
Natural gas sales	$1,103.9	$1,147.7	$786.9	($  43.8)	$360.8
Oil and NGL sales	158.5	237.5	164.2	(79.0)	73.3
Other	4.9	6.9	4.9	(2.0)	2.0
Total Revenues	1,267.3	1,392.1	956.0	(124.8)	436.1
OPERATING EXPENSES
Operating and maintenance	127.5	125.4	87.9	2.1	37.5
General and administrative	68.0	55.8	56.3	12.2	(0.5)
Production and other taxes	58.3	104.0	60.1	(45.7)	43.9
Depreciation, depletion and amortization	512.8	330.9	243.5	181.9	87.4
Exploration	25.0	29.3	22.0	(4.3)	7.3
Abandonment and impairment	20.3	44.6	10.8	(24.3)	33.8
Natural gas purchases		0.5	2.2	(0.5)	(1.7)
Total Operating Expenses	811.9	690.5	482.8	121.4	207.7
Net gain (loss) from asset sales	1.6	60.4	(0.6)	(58.8)	61.0
Operating Income	$ 457.0	$ 762.0	$472.6	($ 305.0)	$289.4
Operating Statistics
Production Volumes
Natural gas (Bcf)	168.7	151.9	121.9	16.8	30.0
Oil and NGL (MMbbl)	3.5	3.3	3.0	0.2	0.3
Total production (Bcfe)	189.5	171.4	140.2	18.1	31.2
Average daily production (MMcfe)	519.1	468.3	384.1	50.8	84.2
Average realized price, net to the well (including hedges)
Natural gas (per Mcf)	$  6.54	$   7.56	$   6.45	($  1.02)	$  1.11
Oil and NGL (per bbl)	45.91	72.96	53.99	(27.05)	18.97

Questar E&P production volumes totaled 189.5 Bcfe in 2009 compared to 171.4 Bcfe in 2008 and 140.2 Bcfe in 2007. On an energy-equivalent basis, natural gas comprised approximately 89% of Questar E&P 2009 production. A comparison of natural gas-equivalent production by major operating area is shown in the following table:

	Year Ended December 31,			Change
	2009	2008	2007	2009 vs. 2008	2008 vs. 2007
	(in Bcfe)
Midcontinent	87.8	67.8	51.0	20.0	16.8
Pinedale Anticline	61.8	56.8	47.4	5.0	9.4
Uinta Basin	23.2	26.9	25.4	(3.7)	1.5
Rockies Legacy	16.7	19.9	16.4	(3.2)	3.5
Total Questar E&P	189.5	171.4	140.2	18.1	31.2

Net production in the Midcontinent grew 29% or 20 Bcfe to 87.8 Bcfe in 2009 compared to 2008. Midcontinent production growth was driven by the first quarter 2008 acquisition of natural gas development properties in northwest Louisiana, ongoing infill-development drilling in the Cotton Valley and Haynesville formations in the Elm Grove, Thorn Lake and Woodardville

Questar Market Resources 2009 Form 10-K

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fields in northwest Louisiana, continued development of the Granite Wash/Atoka/Morrow play in the Texas Panhandle, and production from new outside-operated Woodford Shale horizontal gas wells in the Anadarko Basin in central Oklahoma.

Questar E&P net production from the Pinedale Anticline in western Wyoming grew 9% to 61.8 Bcfe in 2009 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 have been 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 decreased 14% to 23.2 Bcfe in 2009. Production volumes were adversely impacted by decreased drilling activity in response to low natural gas prices.

Rockies Legacy net production in 2009 decreased 16% to 16.7 Bcfe, 3.2 Bcfe lower than the year-ago period. Production volumes were adversely impacted by decreased drilling activity in response to low natural gas prices. Questar E&P Rockies Legacy properties include all Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin.

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 $6.54 per Mcf compared to $7.56 per Mcf in 2008, a 13% decrease. Realized oil and NGL prices in 2009 averaged $45.91 per bbl, compared with $72.96 per bbl during the prior year, a 37% decrease. A regional comparison of average realized prices, including the impact of hedges, is shown in the following table:

	Year Ended December 31,			Change
	2009	2008	2007	2009 vs. 2008	2008 vs. 2007
Natural gas (per Mcf)
Midcontinent	$ 7.01	$8.63	$7.42	($ 1.62)	$1.21
Rocky Mountains	6.12	6.85	5.90	(0.73)	0.95
Volume-weighted average	6.54	7.56	6.45	(1.02)	1.11
Oil and NGL (per bbl)
Midcontinent	$46.05	$72.82	$54.85	($26.77)	$17.97
Rocky Mountains	45.82	73.05	53.51	(27.23)	19.54
Volume-weighted average	45.91	72.96	53.99	(27.05)	18.97

Questar E&P hedged approximately 77% of gas production in 2009 with fixed price swaps. An additional 15% of gas production was subject to basis-only swaps. In 2008, approximately 82% of gas production was hedged with fixed price swaps. An additional 3% of gas production was subject to basis-only swaps. Hedging increased Questar E&P gas revenues by $599.3 million in 2009 and increased revenues $125.8 million in 2008. Approximately 42% of 2009 and 50% of 2008 Questar E&P oil production was hedged with fixed price swaps. Oil hedges increased oil revenues by $1.6 million in 2009 and reduced oil revenues $31.9 million in 2008. The net mark-to-market effect of gas-basis-only swaps is reported in the Consolidated Statements of Income below operating income. Derivative positions as of December 31, 2009, are summarized in Note 6 to the consolidated financial statements in Item 8 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 11% to $4.39 per Mcfe in 2009 versus $3.94 per Mcfe in 2008. Questar E&P production costs are summarized in the following table:

	Year Ended December 31,			Change
	2009	2008	2007	2009 vs. 2008	2008 vs. 2007
	(per Mcfe)
Depreciation, depletion and amortization	$2.71	$1.93	$1.74	$0.78	$0.19
Lease operating expense	0.67	0.73	0.63	(0.06)	0.10
General and administrative expense	0.36	0.33	0.40	0.03	(0.07)
Allocated-interest expense	0.34	0.34	0.18		0.16

Questar Market Resources 2009 Form 10-K

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Production taxes	0.31	0.61	0.43	(0.30)	0.18
Total Production Costs	$4.39	$3.94	$3.38	$0.45	$0.56

Production volume-weighted per-unit depreciation, depletion and amortization (DD&A) expense increased compared to 2008 primarily due to price-related negative reserve revisions in certain fields and the growing proportion of total production from fields in the Midcontinent that have higher DD&A rates. Lease operating expense per Mcfe decreased primarily as a result of higher production volumes and reduced well-workover activity. General and administrative expense per Mcfe increased as a result of increased labor and outside services. Allocated interest expense per Mcfe of production was unchanged. Production taxes per Mcfe decreased in 2009 as the result of lower natural gas and oil sales prices. In most states, the Company pays production taxes based on a percentage of sales prices excluding the impact of hedges.

Questar E&P exploration expense decreased $4.3 million or 15% in 2009 compared to 2008. Abandonment and impairment expense decreased $24.3 million or 54% in 2009 compared to 2008 primarily due to 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.

Major Questar E&P Operating Areas

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 and Louisiana. With the exception of northwest Louisiana, the Granite Wash play in the Texas Panhandle and the Woodford Shale "Cana" play in western Oklahoma, Questar E&P Midcontinent leasehold interests are fragmented, with no significant concentration of property interests. In aggregate, Midcontinent properties comprised 1,100.5 Bcfe or 40% of Questar E&P total proved reserves at December 31, 2009.

Questar E&P has approximately 46,000 net acres of Haynesville Shale lease rights in northwest Louisiana. The true vertical depth to 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 48 (operated and non-operated) horizontal Haynesville Shale wells in 2010. As of December 31, 2009, Questar E&P had seven operated rigs drilling in the project area and operated or had working interests in 31 Haynesville formation wells and 610 total producing wells in northwest Louisiana compared to six Haynesville formation wells and 539 total producing wells at December 31, 2008.

Questar E&P has approximately 26,000 net acres of Woodford Shale lease rights in Blaine, Caddo and Canadian Counties in western Oklahoma. The true vertical depth to the top of the Woodford Shale ranges from approximately 11,000 feet to 14,000 feet across Questar E&P's leasehold. Questar E&P intends to drill or participate in up to 44 horizontal Woodford Shale wells in 2010. As of December 31, 2009, Questar E&P had one operated rig drilling in the project area and operated or had working interests in 49 producing Woodford Shale wells in western Oklahoma compared to 13 at December 31, 2008.

Questar E&P has over 25,000 net acres of Granite Wash lease rights in the Texas Panhandle and western Oklahoma and has been drilling vertical Granite Wash wells in the Texas Panhandle for over a decade. In the past year, other operators have drilled several successful horizontal wells in the Granite Wash Play. The true vertical depth to the top of the Granite Wash interval ranges from approximately 11,100 feet to 15,900 feet across Questar E&P's leasehold. As of December 31, 2009, Questar E&P had one rig drilling horizontal Granite Wash wells in the Texas Panhandle and had working interests in 10 producing horizontal Granite Wash wells in the Texas Panhandle or Washita County, Oklahoma compared to four wells at December 31, 2008. Questar E&P intends to drill or participate in up to 21 horizontal Granite Wash wells in 2010.

Pinedale Anticline

As of December 31, 2009, Market Resources (including both Questar E&P and Wexpro) operated and had working interests in 427 producing wells on the Pinedale Anticline compared to 331 at December 31, 2008. Of the 427 producing wells, Questar E&P has working interests in 405 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 126 of the 427 producing wells.

Questar Market Resources 2009 Form 10-K

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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. 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. The true vertical depth to the top of the Lance Pool tight gas sand reservoir interval ranges from 8,500 to 9,500 feet across Market Resources' acreage.

At December 31, 2009, Questar E&P had booked 432 proved undeveloped locations on a combination of 5-, 10- and 20-acre density and reported estimated net proved reserves at Pinedale of 1,300.7 Bcfe, or 47% of Questar E&P total proved reserves. The Company continues to evaluate development on five-acre density at Pinedale. If five-acre-density development is appropriate for a majority of its leasehold, the Company currently estimates that up to 1,400 additional wells will be required to fully develop the Lance Pool on its acreage.

Uinta Basin

As of December 31, 2009, Questar E&P had an operating interest in 2,334 gross producing wells in the Uinta Basin of eastern Utah, compared to 909 at December 31, 2008. The significant increase in well count was due to the inclusion of Questar E&P acreage within the outside operated Greater Monument Butte enhanced recovery unit in 2009; resulting in Questar E&P having a very small interest in 1,313 wells. At December 31, 2009, Questar E&P had booked nine proved undeveloped locations and reported estimated net proved reserves in the Uinta Basin of 197.7 Bcfe or 7% of Questar E&P total proved reserves. Uinta Basin reserves declined 24% due to lower average 2009 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 244,000 net 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's Rockies Legacy division. Most of the properties are located in the Greater Green River Basin of western Wyoming. In aggregate, Rockies Legacy properties comprised 148.0 Bcfe or 6% of Questar E&P total proved reserves at December 31, 2009. Exploration and development activity for 2010 includes wells in the San Juan, Paradox, Powder River, Green River, Vermillion and Williston Basins.

Questar E&P has approximately 80,000 net acres of Bakken formation lease rights in Mountrail, McLean and McKenzie counties in North Dakota. The true vertical depth to the top of the Bakken formation ranges from approximately 9,500 feet to 10,000 feet across Questar E&P's leasehold. The Three Forks Sanish formation lies approximately 60-70 feet below the middle Bakken formation and is also a target for horizontal drilling. Questar E&P intends to drill or participate in 20-25 horizontal Bakken or Three Forks Sanish wells in 2010. As of December 31, 2009, Questar E&P had one operated rig drilling in the project area and operated or had working interests in 26 producing Bakken or Three Forks Sanish wells in North Dakota compared to 15 at December 31, 2008.

Wexpro

Wexpro reported net income of $80.7 million in 2009 compared to $73.9 million in 2008, a 9% increase and $59.2 million in 2007. 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 $431.9 million at December 31, 2009, an increase of $21.3 million or 5% since December 31, 2008. Wexpro produced 48.2 Bcf of cost-of-service gas in 2009.

MIDSTREAM FIELD SERVICES – Questar Gas Management

Gas Management reported net income of $69.4 million in 2009 compared to $81.5 million in 2008, a 15% decrease and $55.3 million in 2007. Net income was impacted by lower processing margins. Following is a summary of Gas Management financial and operating results:

	Year Ended December 31,			Change
	2009	2008	2007	2009 vs. 2008	2008 vs. 2007
	(in millions)
Operating Income
REVENUES
Processing	$104.5	$137.0	$  94.9	($32.5)	$  42.1
Gathering	127.3	121.0	94.0	6.3	27.0

Questar Market Resources 2009 Form 10-K

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Other gathering	32.8	32.2	17.4	0.6	14.8
Total Revenues	264.6	290.2	206.3	(25.6)	83.9
OPERATING EXPENSES
Operating and maintenance	75.0	95.0	83.6	(20.0)	11.4
General and administrative	25.0	23.7	17.2	1.3	6.5
Production and other taxes	4.6	2.6	1.4	2.0	1.2
Depreciation, depletion and amortization	44.3	28.7	19.1	15.6	9.6
Abandonment and impairments		0.8	0.4	(0.8)	0.4
Total Operating Expenses	148.9	150.8	121.7	(1.9)	29.1
Net loss from asset sales	(0.1)			(0.1)
Operating Income	$115.6	$139.4	$  84.6	($23.8)	$  54.8
Operating Statistics
Natural gas processing volumes
NGL sales (MMgal)	101.6	89.5	76.5	12.1	13.0
NGL sales price (per gal)	$0.71	$1.18	$0.98	($0.47)	$0.20
Fee-based processing volumes (in millions of MMBtu)
For unaffiliated customers	102.4	87.4	44.1	15.0	43.3
For affiliated customers	107.6	114.1	82.5	(6.5)	31.6
Total Fee Based Processing Volumes	210.0	201.5	126.6	8.5	74.9
Fee-based processing (per MMBtu)	$0.15	$0.14	$0.15	$0.01	($0.01)
Natural gas gathering volumes (in millions of MMBtu)
For unaffiliated customers	247.1	224.0	162.1	23.1	61.9
For affiliated customers	166.7	168.5	128.1	(1.8)	40.4
Total Gas Gathering Volumes	413.8	392.5	290.2	21.3	102.3
Gas gathering revenue (per MMBtu)	$0.31	$0.31	$0.32		($0.01)

Processing margin (processing revenue minus plant operating and maintenance expense, which includes processing plant-shrink) in 2009 decreased 15% to $66.1 million compared to $78.1 million in 2008. Fee-based gas processing volumes were 210.0 million MMBtu in 2009, a 4% increase compared to 2008. In 2009, fee-based gas processing revenues increased 12% or $3.4 million, while the frac spread from keep-whole processing decreased 24% or $13.5 million. Approximately 81% of Gas Management's net operating revenue (revenue minus processing plant-shrink) in 2009 was derived from fee-based contracts, up from 75% in 2008. Gas Management may use forward sales contracts to reduce margin volatility associated with keep-whole contracts. Forward sales contracts had no impact in 2009 and reduced NGL revenues by $1.4 million in 2008.

Gathering margin (gathering revenue minus gathering operating and maintenance expense) in 2009 increased 5% to $123.5 million compared to $117.1 million in 2008. Expanding Pinedale production and new projects serving third parties in the Uinta Basin contributed to a 10% increase in third-party volumes in 2009. Gathering volumes increased 21.3 million MMBtu, or 5% to 413.8 million MMBtu in 2009. Rendezvous was consolidated with Gas Management beginning in 2008. Rendezvous provides gas gathering services for the Pinedale and Jonah producing areas of Wyoming.

ENERGY MARKETING – Questar Energy Trading

Energy Trading net income was $8.5 million in 2009, a decrease of 62% compared to 2008 net income of $22.1 million and 2007 net income of $20.8 million as a result of lower marketing and storage margins. Revenues from unaffiliated customers were $425.6 million in 2009 compared to $608.1 million in 2008, a 30% decrease, primarily the result of lower natural gas prices. The weighted-average natural gas sales price decreased 48% in 2009 to $3.29 per MMBtu, compared to $6.34 per MMBtu in 2008.

Questar Market Resources 2009 Form 10-K

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Consolidated Results below Operating Income

Interest and Other Income

Interest and other income decreased $7.6 million in 2009 compared with 2008 due to less activity in sales of inventory. Interest and other income increased $4.9 million or 51% in 2008 compared with 2007 primarily from gains on inventory sales.

Income from unconsolidated affiliates

Income from unconsolidated affiliates was $2.7 million in 2009 compared to $1.7 million in 2008 and $8.9 million in 2007. Rendezvous Gas Services, which represented the majority of income from unconsolidated affiliates in 2007, was consolidated beginning in 2008.

Realized and unrealized gain (loss) on basis-only swaps

The Company has used basis-only swaps to manage the risk of widening basis differentials. Basis-only swaps do not qualify for hedge accounting. As of December 31, 2009, all of the Company's basis-only swaps were paired with fixed-price swaps and re-designated as cash flow hedges. Changes in the fair value of the derivative instruments subsequent to the re-designation were recorded in Accumulative Other Comprehensive Income. Fair value changes occurring prior to re-designation were recorded in income. The Company recognized unrealized mark-to-market losses of $164.0 million in 2009, $79.2 million in 2008 and $5.7 million gain in 2007. The Company realized losses of $25.6 million on settlements of basis-only swaps in 2009.

Interest expense

Interest expense rose 13% in 2009 compared with 2008 and 75% in 2008 compared to 2007 due primarily to permanent financing activities associated with the purchase of natural gas development properties in northwest Louisiana. Interest rates on Questar's commercial-paper borrowings in 2009 averaged less than 1% per annum after reaching the highest level in recent years in September 2008.

Income taxes

The effective combined federal and state income tax rate was 35.6% in 2009 compared with 35.3% in 2008 and 36.4% in 2007.

Investing Activities

Capital spending in 2009 amounted to $1,314.6 million. The details of capital expenditures in 2009 and 2008 and a forecast for 2010 are shown in the table below:

	Year Ended December 31,
	2010 Forecast	2009	2008
	(in millions)
Questar E&P	$   873.6	$1,108.6	$1,777.3
Wexpro	100.0	116.2	143.8
Gas Management	289.0	88.3	357.9
Other	1.2	1.5	1.5
Total capital expenditures	$1,263.8	$1,314.6	$2,280.5

Questar E&P and Wexpro

Questar E&P capital expenditures decreased in 2009 compared to 2008 due to lower property acquisitions in 2009 and a commodity-price constrained drilling program in 2009. In February 2008, Questar E&P acquired natural gas development properties in northwest Louisiana for an aggregate purchase price of $652.1 million. During 2009, Questar E&P and Wexpro participated in 437 wells (197.6 net), resulting in 193.6 net successful gas and oil wells and 4.0 net dry or abandoned wells. The 2009 net drilling-success rate was 98.0%. There were 116 gross wells in progress at year-end.

Questar Gas Management

Market Resources also increased investment in its midstream gathering and processing-services business to expand capacity in both western Wyoming and eastern Utah in anticipation of growing production volumes.

Financing Activities

Questar issues commercial paper rated A-2 by Standard & Poor's Corporation and P-2 by Moody's Investors Services, to meet short-term financing requirements and may loan proceeds to Market Resources. Questar maintains committed credit lines with banks to provide liquidity support. The table below sets forth credit ratings for Questar and Market Resources. The outlook associated with each rating is deemed stable by each rating agency:

Questar Market Resources 2009 Form 10-K

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	Moody's	Standard & Poor's
Market Resources	Baa3	BBB+
Questar commercial paper	P-2	A-2

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, 2009:

	Payments Due by Year
	Total	2010	2011	2012	2013	2014	After 2014
	(in millions)
Long-term debt	$1,350.0		$150.0		$200.0		$1,000.0
Interest on fixed-rate long-term debt	585.7	$77.4	68.0	$66.1	66.1	$66.1	242.0
Drilling contracts	79.2	55.4	19.8	4.0
Transportation contracts	444.0	17.3	37.2	42.0	40.2	39.3	268.0
Operating leases	19.2	4.8	4.8	4.4	3.0	1.0	1.2
Total	$2,478.1	$154.9	$279.8	$116.5	$309.3	$106.4	$1,511.2

The Company had $200.0 million of variable-rate long-term debt outstanding under its revolving credit facility with an interest rate of 0.73% at December 31, 2009.

Critical Accounting Policies, Estimates and Assumptions

Market Resources' significant accounting policies are described in Note 1 to the consolidated financial statements included in Item 8 of Part II of this Annual Report. The Company's consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles. The preparation of consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. The following accounting policies may involve a higher degree of complexity and judgment on the part of management.

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. See Note 16 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 Market Resources 2009 Form 10-K

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Questar E&P engages an independent reservoir-engineering consultant 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 and costless collars, 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 Accumulated Other Comprehensive Income (AOCI) depending on the structure of the derivative. The Company has historically structured substantially all energy-derivative instruments as cash flow hedges as defined in ASC 815 "Derivatives and Hedging." Changes in the fair value of cash flow hedges are recorded on the balance sheet and in AOCI 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 the SEC's "Modernization of Oil and Gas Reporting," which amends the disclosures for oil and gas producers.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market Resources' primary market-risk exposure arises from changes in the market price 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 fully utilize the contractual capacity of these transportation commitments.

Commodity-Price Risk Management

Market Resources' subsidiaries use commodity-price derivative instruments in the normal course of business to reduce 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-marketing transactions.

As of December 31, 2009, Market Resources held commodity-price derivative contracts for 409.6 million MMBtu of natural gas and 2.7 million barrels of oil. A year earlier Market Resources held derivative contracts for 234.4 million MMBtu of natural gas, 0.7 million barrels of oil and natural gas basis-only swaps on an additional 204.9 Bcf. A table of the Market Resources derivative positions for equity production as of December 31, 2009, is shown below:

	Cash flow	Basis-only
	Hedges	Swaps	Total
	(in millions)
Net fair value of gas- and oil-derivative contracts   outstanding at Dec. 31, 2008	$543.6	($75.5)	$468.1
Contracts realized or otherwise settled	(431.2)	14.7	(416.5)
Change in gas and oil prices on futures markets	(300.7)	60.8	(239.9)
Contracts added	87.4		87.4

Questar Market Resources 2009 Form 10-K

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Contracts re-designated as fixed-price swaps	239.4	(239.4)
Net Fair Value Of Gas- and Oil-Derivative Contracts   Outstanding at Dec. 31, 2009	$138.5	($239.4)	($100.9)

A table of the net fair value of gas- and oil-derivative contracts as of December 31, 2009, is shown below. Cash flow hedges representing 72% of the net fair value will settle in the next 12 months and will be reclassified from AOCI:

	Cash flow	Basis-only
	Hedges	Swaps	Total
	(in millions)
Contracts maturing by Dec. 31, 2010	$100.2	($121.7)	($21.5)
Contracts maturing between Jan. 1, 2011 and Dec. 31, 2011	21.6	(117.7)	(96.1)
Contracts maturing between Jan. 1, 2012 and Dec. 31, 2012	9.3		9.3
Contracts maturing between Jan. 1, 2013 and Dec. 31, 2013	7.4		7.4
Net Fair Value Of Gas- and Oil-Derivative Contracts   Outstanding at Dec. 31, 2009	$138.5	($239.4)	($100.9)

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

	At December 31,
	2009	2008
	(in millions)
Net fair value – asset (liability)	($100.9)	$468.1
Value if market prices of gas and oil and basis differentials decline by 10%	174.2	590.4
Value if market prices of gas and oil and basis differentials increase by 10%	(375.8)	345.9

Credit Risk

Market Resources requests credit support and, in some cases, prepayment from companies that pose unfavorable credit risks. Market Resources' five largest customers are Sempra Energy Trading Corp., Chevron USA Inc., Enterprise Products Operating, Texla Energy Management Inc. and BP Energy Company. Sales to these companies accounted for 23% of Market Resources revenues before elimination of intercompany transactions in 2009, and their accounts were current at December 31, 2009.

Interest-Rate Risk

The fair value of fixed-rate debt is subject to change as interest rates fluctuate. The Company's ability to borrow and the rates quoted by lenders can be adversely affected by the illiquid credit markets as described in Item 1A. Risk Factors of Part I of this Annual Report on Form 10-K. The Company had $1,148.7 million of fixed-rate long-term debt with a fair value of $1,194.1 million at December 31, 2009. A year earlier the Company had $849.1 million of fixed-rate long-term debt with a fair value of $730.9 million. If interest rates had declined 10%, fair value would increase to $1,236.0 million in 2009 and $767.8 million in 2008. The fair value calculations do not represent the cost to retire the debt securities.

Climate-Change Risk

Federal and state courts and administrative agencies are considering the scope and scale of climate-change regulation under various laws pertaining to the environment, energy use and development, and greenhouse gas emissions. Market Resources' ability to access and develop new natural gas reserves may be restricted by climate-change regulation. There are bills pending in Congress that would regulate greenhouse gas emissions through a cap-and-trade system under which emitters would be required to buy allowances for offsets of emissions of greenhouse gases. The EPA has adopted final regulations for the measurement and reporting of greenhouse gases emitted from certain large facilities (25,000 tons/year of CO₂ equivalent) beginning with operations in 2010. The first report is to be filed with the EPA by March 31, 2011. In addition, several of the states in which Market Resources operates are considering various greenhouse gas registration and reduction programs. Carbon dioxide regulation could increase the price of natural gas, restrict access to or the use of natural gas, and/or reduce natural gas demand. Federal, state and local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for natural gas. While future climate-change regulation is likely, it is too early to predict how this regulation will affect Market Resources' business, operations or financial results. It is uncertain whether Market Resources' operations and properties, located in the Rocky Mountain and Midcontinent regions of the United States, are exposed to possible

Questar Market Resources 2009 Form 10-K

26

physical risks, such as severe weather patterns, due to climate change as a result of man-made greenhouse gases. However, management does not believe that such physical risks are reasonably likely to have a material effect on the Company's financial condition or results of operations.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Financial Statements:

Page No.

Report of Independent Registered Public Accounting Firm

28

Consolidated Statements of Income, three years ended December 31, 2009

29

Consolidated Balance Sheets at December 31, 2009 and 2008

30

Consolidated Statements of Equity, three years ended December 31, 2009

31

Consolidated Statements of Cash Flows, three years ended December 31, 2009

33

Notes Accompanying the Consolidated Financial Statements

35

Financial Statement Schedule:

Valuation and Qualifying Accounts, for the three years ended December 31, 2009

59

All other schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or Notes thereto.

Questar Market Resources 2009 Form 10-K

27

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, 2009 and 2008, and the related consolidated statements of income, shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2009. 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 presentation. 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, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, 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 consolidated financial statements, during 2009, the Company adopted a new accounting standard relating to the presentation of noncontrolling interests in consolidated subsidiaries and the Company adopted new oil and gas reserve estimation and disclosure requirements.

/s/Ernst & Young

Ernst & Young

Salt Lake City, Utah

March 5, 2010

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28

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2009	2008	2007
	(in millions)
REVENUES
From unaffiliated customers	$1,949.0	$2,297.2	$1,671.3
From affiliated companies	249.5	232.9	172.1
Total Revenues	2,198.5	2,530.1	1,843.4
OPERATING EXPENSES
Cost of natural gas and other products sold (excluding operating     expenses shown separately)	411.1	575.1	474.7
Operating and maintenance	222.8	243.6	187.9
General and administrative	108.6	91.7	91.3
Production and other taxes	82.9	144.6	81.6
Depreciation, depletion and amortization	617.9	410.0	295.1
Exploration	25.0	29.3	22.0
Abandonment and impairment	20.3	45.4	11.2
Wexpro Agreement-oil income sharing	1.0	6.1	4.9
Total Operating Expenses	1,489.6	1,545.8	1,168.7
Net gain (loss) from asset sales	1.2	60.2	(1.3)
OPERATING INCOME	710.1	1,044.5	673.4
Interest and other income	7.0	14.6	9.7
Income from unconsolidated affiliates	2.7	1.7	8.9
Unrealized and realized gain (loss) on basis-only swaps	(189.6)	(79.2)	5.7
Interest expense	(70.3)	(62.2)	(35.6)
INCOME BEFORE INCOME TAXES	459.9	919.4	662.1
Income taxes	(163.8)	(324.9)	(241.3)
NET INCOME	296.1	594.5	$   420.8
Net income attributable to noncontrolling interest	(2.6)	(9.0)
NET INCOME ATTRIBUTABLE TO MARKET RESOURCES	$   293.5	$   585.5	$   420.8

See notes accompanying the consolidated financial statements

Questar Market Resources 2009 Form 10-K

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QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2009	2008
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$     17.5	$     20.3
Federal income taxes receivable		11.1
Accounts receivable, net	220.0	265.2
Accounts receivable from affiliates	28.0	28.1
Fair value of derivative contracts	128.2	431.3
Inventories, at lower of average cost or market
Gas and oil storage	17.5	23.6
Materials and supplies	76.5	86.8
Prepaid expenses and other	29.9	28.0
Deferred income taxes – current	25.6
Total Current Assets	543.2	894.4
Property, Plant and Equipment – successful efforts     method of accounting for gas and oil properties
Questar E&P
Proved properties	5,721.5	4,948.2
Unproved properties, not being depleted	389.6	193.2
Wexpro	1,022.5	911.5
Gas Management	1,037.5	976.6
Energy Trading and other	42.4	41.3
Total Property, Plant and Equipment	8,213.5	7,070.8
Less accumulated depreciation, depletion and amortization
Questar E&P	1,890.9	1,421.8
Wexpro	428.6	374.9
Gas Management	198.7	159.3
Energy Trading and other	10.1	8.4
Total Accumulated Depreciation, Depletion and Amortization	2,528.3	1,964.4
Net Property, Plant and Equipment	5,685.2	5,106.4
Investment in unconsolidated affiliates	43.9	40.8
Other Assets
Goodwill	60.1	60.2
Contract receivable from Questar Gas	3.3	3.6
Fair value of derivative contracts	61.2	106.3
Other noncurrent assets	22.5	22.7
Total Other Assets	147.1	192.8
TOTAL ASSETS	$6,419.4	$6,234.4

Questar Market Resources 2009 Form 10-K

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LIABILITIES AND EQUITY

	December 31,
	2009	2008
	(in millions)
Current Liabilities
Notes payable to Questar	$     39.3	$     89.4
Accounts payable and accrued expenses	318.8	411.7
Accounts payable to affiliates	16.2	14.1
Federal income taxes payable	16.7
Production and other taxes	46.6	46.2
Interest payable	26.3	19.5
Fair value of derivative contracts	149.7	0.5
Deferred income taxes – current		138.1
Total Current Liabilities	613.6	719.5
Long-term debt	1,348.7	1,299.1
Deferred income taxes	1,279.4	1,138.3
Asset retirement obligations	185.0	171.2
Fair value of derivative contracts	140.6	69.0
Other long-term liabilities	43.4	57.9
Commitments and contingencies – Note 9
EQUITY
Common stock – par value $1 per share;
25.0 million shares authorized; 4.3 million shares issued and outstanding	4.3	4.3
Additional paid-in capital	124.2	141.9
Retained earnings	2,538.2	2,262.1
Accumulated other comprehensive income	87.1	341.6
Total Common Shareholder's Equity	2,753.8	2,749.9
Noncontrolling interest	54.9	29.5
Total Equity	2,808.7	2,779.4
TOTAL LIABILITIES AND EQUITY	6,419.4	$6,234.4

See notes accompanying the consolidated financial statements

Questar Market Resources 2009 Form 10-K

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QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF EQUITY

		Additional		Accum. Other	Non-	Comprehensive
	Common	Paid-in	Retained	Comprehensive	controlling	Income
	Stock	Capital	Earnings	Income (Loss)	Interest	(Loss)
	(in millions)
Balances at January 1, 2007	$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
Balances at December 31, 2007	4.3	130.9	1,693.9	31.0
2008 net income			585.5		$  9.0	$594.5
Dividends paid			(17.3)
Share-based compensation		11.0
Consolidation of noncontrolling interest					29.8
Distribution to noncontrolling interest					(9.3)
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
Balances at December 31, 2008	4.3	141.9	2,262.1	341.6	29.5
2009 net income			293.5		2.6	$296.1
Dividends paid			(17.4)
Share-based compensation		13.9
Noncontrolling interest equity adjustment		(28.5)			28.5
Tax on equity adjustment		(3.1)
Distribution to noncontrolling interest					(5.7)
Other comprehensive income
Change in unrealized fair value of derivatives				(405.1)		(405.1)
Income taxes				150.6		150.6
Total comprehensive income						$  41.6
Balances at December 31, 2009	$4.3	$124.2	$2,538.2	$87.1	$54.9

See notes accompanying the consolidated financial statements

Questar Market Resources 2009 Form 10-K

32

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2009	2008	2007
	(in millions)
OPERATING ACTIVITIES
Net income	$ 296.1	$ 594.5	$ 420.8
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization	619.5	411.5	296.0
Deferred income taxes	127.8	335.3	183.0
Abandonment and impairment	20.3	45.4	11.2
Share-based compensation	13.9	11.0	8.9
Dry exploratory well expense	4.7	9.7	12.3
Net (gain) loss from asset sales	(1.2)	(60.2)	1.3
(Income) from unconsolidated affiliates	(2.7)	(1.7)	(8.9)
Distributions from unconsolidated affiliates	1.1	0.5	10.4
Unrealized mark-to-market (gain) loss on basis-only swaps	164.0	79.2	(5.7)
Other operating	0.1	1.0	(1.0)
Changes in operating assets and liabilities
Accounts receivable	45.3	(28.9)	(6.7)
Inventories	16.4	(54.0)	5.8
Prepaid expenses	(1.9)	(9.8)	4.3
Accounts payable and accrued expenses	12.3	14.4	(34.0)
Federal income taxes	24.9	(6.5)	(3.2)
Other	(16.8)	12.7	1.0
NET CASH PROVIDED BY OPERATING ACTIVITIES	1,323.8	1,354.1	895.5
INVESTING ACTIVITIES
Property, plant and equipment including dry exploratory well expense	(1,313.1)	(2,259.0)	(929.1)
Other investments	(1.5)	(21.5)	(14.8)
Total capital expenditures	(1,314.6)	(2,280.5)	(943.9)
Proceeds from disposition of assets	14.2	103.4	4.6
NET CASH USED IN INVESTING ACTIVITIES	(1,300.4)	(2,177.1)	(939.3)
FINANCING ACTIVITIES
Change in notes receivable from Questar		103.2	(33.4)
Change in notes payable to Questar	(50.1)	(29.5)	(23.7)
Long-term debt issued, net of issuance costs	422.0	1,395.2	100.0
Long-term debt repaid	(375.0)	(600.0)
Distribution to noncontrolling interest	(5.7)	(9.3)
Dividends paid	(17.4)	(17.3)	(17.3)
Other		1.0

Questar Market Resources 2009 Form 10-K

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NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(26.2)	843.3	25.6
Change in cash and cash equivalents	(2.8)	20.3	(18.2)
Beginning cash and cash equivalents	20.3		18.2
Ending cash and cash equivalents	$    17.5	$  20.3	$   -
Supplemental Disclosure of Cash Paid During the Year for:
Interest	$62.4	$55.9	$34.5
Income taxes	8.4	2.5	64.9

See notes accompanying the consolidated financial statements

Questar Market Resources 2009 Form 10-K

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QUESTAR MARKET RESOURCES, INC.

NOTES ACCOMPANYING THE 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.

Accounting Standards References

In July 2009, the Financial Accounting Standards Board (FASB) completed a revision of non-governmental U.S. generally accepted accounting principles (GAAP) into a single authoritative source and issued a codification of accounting rules and references. Authoritative standards included in the codification are designated by their Accounting Standards Codification (ASC) topical reference, and revised standards are designated as Accounting Standards Updates (ASU), with a year and assigned sequence number. The codification effort, while not creating or changing accounting rules, changed how users would cite accounting regulations. Citations in financial statements must identify the sections within the new codification. The codification is effective for interim and annual periods ending after September 15, 2009. The Company is complying with the new codification standards.

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 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. Gas Management's ownership interest increased from 50% to 78%. All significant intercompany accounts and transactions have been eliminated in consolidation.

On January 1, 2009, Market Resources adopted "Noncontrolling Interests in Consolidated Financial Statements" (ASC 810-10-65-1) for the accounting, reporting and disclosure of noncontrolling interests. The new guidance requires that noncontrolling interest, previously known as minority interest, be clearly identified, labeled, and presented in the consolidated financial statements 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 in the consolidated income statement; 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 new provisions are applied prospectively from the date of adoption, except for the presentation and disclosure requirements, which are applied retrospectively for all periods presented.

SEC's Modernization of Oil and Gas Reporting Requirements

In December 2008, the SEC issued Release No. 33-8995, "Modernization of Oil and Gas Reporting," which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. The most significant amendments affecting the Company include the following: (i) economic producibility of reserves and discounted cash flows are to be based on the arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless contractual arrangements designate the price to be used; and (ii) reserves may be estimated and categorized through the use of reliable technologies. Release No. 33-8995 is effective for financial statements for fiscal years ending on or after December 31, 2009.

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

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35

impairment when events indicate that the fair value of the investment may be below the Company's carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in the determination of net income.

The principal unconsolidated affiliates and Market Resources' ownership percentage as of December 31, 2009, were Uintah Basin Field Services, LLC, (38%) and Three Rivers Gathering, LLC, (50%), both limited liability companies engaged in gathering and compressing natural gas.

Use of Estimates

The preparation of consolidated financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The Company also incorporates estimates of proved developed and proved gas and oil reserves in the calculation of depreciation, depletion and amortization rates of its gas and oil properties. Changes in estimated quantities of its reserves could impact the Company's reported financial results as well as disclosures regarding the quantities and value of proved gas and oil reserves. 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 $4.2 million in 2009 and $3.1 million in 2008.

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 and third-party natural gas, oil and NGL 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 ASC 845-10-25-4 "Accounting for Purchases and Sales of Inventory with the Same Counterparty."

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 10 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 or Payable to Questar

Notes receivable from or payable to Questar represent interest bearing demand notes for cash loaned to or borrowed from Questar until needed in operations. The funds are centrally managed by Questar. Amounts loaned to Questar 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 with the exception of compressor maintenance costs, which are capitalized and depreciated based on hours of usage in accordance with ASC 360-10-25-5.

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. Geological and geophysical studies and other exploratory activities are expensed as incurred. Costs of production and general-

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36

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 an exploratory 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 10). 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-production method. The following rates per Mcfe represent the volume-weighted average depreciation, depletion and amortization rates of the Company's capitalized costs:

	Year ended December 31,
	2009	2008	2007
Gas and oil properties, per Mcfe	$2.71	$1.93	$1.74
Cost-of-service gas and oil properties, per Mcfe	1.44	1.27	1.09

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.

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37

Goodwill and Other Intangible Assets

Goodwill represents the excess of the amount paid 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, which is recorded in interest and other income. AFUDC on equity funds amounted to $1.9 million in 2009, $3.1 million in 2008 and $1.3 million in 2007 and increased interest and other income in the Consolidated Statements of Income.

Derivative Instruments

In November 2008, the Company adopted the updated disclosure provisions of ASC 815 "Derivatives and Hedging" and modified the disclosures accordingly. 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 AOCI 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 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.

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 revenues or cost of sales in the month of settlement.

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 income.

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

Questar Market Resources 2009 Form 10-K

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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 Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

Bad debt expense associated with accounts receivable for the year ended December 31, amounted to $0.4 million in 2009 and 2008 and $0.1 million in 2007. The allowance for bad-debt expenses was $3.0 million at December 31, 2009, and $2.7 million at December 31, 2008.

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 are provided for the temporary differences arising between the book and tax-carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. The Company records interest earned on income tax refunds in interest and other income and records penalties and interest charged on tax deficiencies in interest expense.

ASC 740 "Income Taxes" specifies 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. 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, 2009, 2008 and 2007. Income tax returns for 2006 and subsequent years are subject to examination.

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), including certain officers and employees of Market Resources. Since January 1, 2006, the fair value of stock options is expensed during the vesting period. Questar uses the Black-Scholes-Merton mathematical model in estimating the fair value of stock options for accounting purposes. The granting of restricted shares results in recognition of compensation cost measured at the grant-date market price. Questar uses an accelerated method in recognizing share-based compensation costs with graded-vesting periods. See Note 11 for further discussion on share-based compensation.

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). As reported in the Consolidated Statements of Equity, other comprehensive income (loss) consists of changes in the market value of commodity-based derivative instruments. 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 physical gas, oil or NGL underlying the derivative instrument is sold.

Unrealized gain on derivatives is a component of AOCI on the Consolidated Balance Sheets. The following table sets forth the changes in unrealized gain on derivatives, net of income taxes, during 2009:

	Year Ended
	December 31, 2009
	(in millions)
Balance at January 1,	$341.6
Realized or otherwise settled	(271.0)
Change due to commodity price changes	(38.3)
Net fair value of hedges added during the year	54.8
Balance at December 31,	$  87.1

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.

Questar Market Resources 2009 Form 10-K

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Reclassifications

Certain reclassifications were made to prior-year consolidated financial statements to conform with the 2009 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 – Property, Plant and Equipment

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. Including 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.

In conjunction with the acquisition of the Louisiana properties, the Company identified and subsequently sold certain outside-operated producing properties and leaseholds in the Gulf Coast region of south Texas. 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.

Abandonment and impairment expense decreased $24.3 million or 54% in 2009 compared to 2008 primarily due to the impairment of certain gas and oil assets in 2008.

Gas Management constructed a gathering pipeline for $203.5 million and contributed the asset to Rendezvous Gas Services LLC (Rendezvous). As a result, Gas Management's ownership interest in Rendezvous increased from 50% to 78%. Common stock was reduced by $31.6 million and noncontrolling interest increased by $28.5 million. Rendezvous operates gas-gathering facilities for Pinedale Anticline and Jonah field producers for delivery to various interstate pipelines.

Note 3 – Asset Retirement Obligations

Market Resources records asset retirement obligations (ARO) when there are legal obligations associated with the retirement of tangible long-lived assets. The Company's ARO apply primarily to abandonment costs associated with gas and oil wells, production facilities and certain other properties. The fair value of retirement costs are estimated by Company personnel based on abandonment costs of similar properties available to field operations and depreciated over the life of the related assets. Revisions to ARO estimates result from changes in expected cash flows or material changes in estimated retirement costs. Income or expense resulting from the settlement of ARO liabilities is included in net gain or (loss) from asset sales 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:

	2009	2008
	(in millions)
ARO liability at January 1,	$171.2	$145.3
Accretion	10.7	9.4
Liabilities incurred	3.0	17.2
Revisions	2.4	1.5
Liabilities settled	(2.3)	(2.2)
ARO liability at December 31,	$185.0	$171.2

Wexpro collects from Questar Gas and deposits in trust certain funds related to estimated ARO costs. The funds are recorded in other noncurrent assets on the Consolidated Balance Sheets and used to satisfy retirement obligations as the properties are abandoned. The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is defined in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the Public Service Commission of Wyoming (PSCW).

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Note 4 – 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.

	2009	2008	2007
	(in millions)
Balance at January 1,	$17.0	$ 1.5	$ 10.5
Additions to capitalized exploratory well costs pending the
determination of proved reserves	51.7	17.0	1.5
Reclassifications to property, plant and equipment after the
determination of proved reserves	(14.3)
Capitalized exploratory well costs charged to expense	(2.7)	(1.5)	(10.5)
Balance at December 31,	$51.7	$17.0	$   1.5

Note 5 - Fair Value Measurements

Beginning in 2008, Market Resources adopted the effective provisions of ASC 820 "Fair Value Measurements and Disclosures." ASC 820 defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair-value measurements. ASC 820 does not change existing guidance as to whether or not an instrument is carried at fair value. ASC 820 establishes a fair-value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets 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 (see Note 6) is based on market prices posted on the NYMEX on the last trading day of the reporting period and industry-standard discounted cash flow models. The Level 3 fair value of derivative contracts is based on NYMEX market prices in combination with unobservable volatility inputs and industry-standard option pricing models. Long-term investments consist of money market and short-term bond index mutual funds, and represent funds held in Wexpro's trust (see Note 3). The fair value of long-term investments is based on quoted prices for the underlying mutual funds, and is considered a Level 1 fair value.

Market Resources primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. Market Resources considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, Market Resources makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique.

Certain of Market Resources' derivative instruments, however, are valued using industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also incorporates nonperformance risk for counterparties and for Market Resources. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with a counterparty exists.

In February 2008, the FASB delayed the effective date of ASC 820 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 delayed provisions of ASC 820 related to nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis. Market Resources did not have any assets or liabilities measured at fair value on a non-recurring basis at December 31, 2009. The fair values of assets and liabilities at December 31, 2009, are shown in the table below:

	Level 1	Level 2	Level 3	Total
	(in millions)
Assets
Long-term investments	$11.7			$   11.7
Derivative contracts - short term		$127.9	$0.3	128.2

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Derivative contracts - long term		56.0	5.2	61.2
Total assets	$11.7	$183.9	$5.5	$201.1
Liabilities
Derivative contracts - short term		$149.7		$149.7
Derivative contracts - long term		140.6		140.6
Total liabilities		$290.3		$290.3

The change in the fair value of Level 3 assets and liabilities is shown below:

	Change in Level 3 Fair Value Measurements
	2009
	(in millions)
Balance at January 1,
Purchases, sales, issuances and settlements (net)
Realized gains and losses
Unrealized gains and losses included in other comprehensive income	$5.5
Balance at December 31,	$5.5

Market Resources did not have any assets or liabilities measured at fair value on a non-recurring basis or Level 3 at December 31, 2008. The fair values of assets and liabilities at December 31, 2008, are shown in the table below:

	Level 1	Level 2	Total
	(in millions)
Assets
Long-term investments	$9.9		$9.9
Derivative contracts - short term		$431.3	431.3
Derivative contracts - long term		106.3	106.3
Total assets	$9.9	$537.6	$547.5
Liabilities
Derivative contracts - short term		$  0.5	$  0.5
Derivative contracts - long term		69.0	69.0
Total liabilities		$  69.5	$69.5

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other notes to the Consolidated Financial Statements in this annual report on Form 10-K:

	Carrying	Estimated	Carrying	Estimated
	Amount	Fair Value	Amount	Fair Value
	December 31, 2009		December 31, 2008
	(in millions)
Financial assets
Cash and cash equivalents	$    17.5	$    17.5	$    20.3	$    20.3
Financial liabilities
Notes payable to Questar	39.3	39.3	89.4	89.4
Long-term debt	1,348.7	1,394.1	1,299.1	1,180.9

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The carrying amounts of cash and cash equivalents and notes payable to Questar approximate fair value. The fair value of fixed-rate long-term debt is based on the discounted present value of future cash flows using the Company's current borrowing rates. The borrowing rates are credit-risk adjusted. The carrying amount of variable-rate long-term debt approximates fair value.

Note 6 - Derivative Contracts

Market Resources' subsidiaries use commodity-price derivative instruments in the normal course of business. Market Resources has established policies and procedures for managing commodity-price risks through the use of derivative instruments. On January 1, 2009, the Company adopted a revision to ASC 815 "Derivatives and Hedging," which requires more detailed information about hedging transactions including the location and effect on the primary consolidated financial statements.

Market Resources uses derivative instruments to support rate of return and cash flow targets and protect earnings from downward movements in commodity prices. However, these same instruments 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 marketing transactions. The volume of production with associated derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. Market Resources may match derivative contracts with up to 100% of forecast production from proved reserves when prices meet earnings and cash flow objectives. Market Resources does not enter into derivative instruments for speculative purposes.

Market Resources uses derivative instruments known as fixed-price swaps and costless collars to realize a known price or range of prices for a specific volume of production delivered into a regional sales point. Swap agreements do not require the physical transfer of natural 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. Collars are combinations of put and call options that have a floor price and a ceiling price and are only triggered if the settlement price is outside the range of the floor and ceiling prices. In the past, Questar E&P has also used natural gas basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials. However, natural gas basis-only swaps exposed the Company to losses from narrowing natural gas price-basis differentials.

Market Resources enters into derivative instruments that do not have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement dates. Derivative-arrangement counterparties are normally financial institutions and energy-trading firms with investment-grade credit ratings. The Company routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties and transacting with multiple counterparties.

All derivative instruments are required to be recorded on the balance sheet as either assets or liabilities measured at their fair values. The designation of a derivative instrument as a hedge and its ability to meet hedge accounting criteria determines how the change in fair value of the derivative instrument is reflected in the consolidated financial statements. A derivative instrument qualifies for hedge accounting, if at inception, the derivative is expected to be highly effective in offsetting the underlying hedged cash flows. Generally, Market Resources' derivative instruments are matched to equity gas and oil production and are highly effective, thus qualifying as cash flow hedges. Changes in the fair value of effective cash flow hedges are recorded as a component of AOCI on the Condensed Consolidated Balance Sheets and reclassified to earnings as gas and oil sales when the underlying physical transactions occur. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. Costless collars qualify for cash flow hedge accounting. A basis-only swap does not qualify for hedge accounting treatment. Market Resources regularly reviews the effectiveness of derivative instruments. The ineffective portion of cash flow hedges and the mark to market adjustment of basis-only swaps are immediately recognized in the determination of net income. The ineffective portion of cash flow hedges was de minimis for the year ended December 31, 2009.

	Year Ended
	December 31, 2009
	(in millions)
Effect of derivative instruments designated as hedges
Revenues
Fixed-price swaps increased revenues	$628.7
Cost Of Natural Gas And Other Products Sold
Fixed-price swaps included in product costs	9.2
Effect of derivative instruments not designated as hedges
Unrealized and realized gain (loss) on basis-only swaps	(189.6)

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Contract settlements in 2009 resulted in a transfer of $271.0 million after-tax income from AOCI to the Consolidated Statements of Income. Effective portions of cash flow hedges resulted in the recognition of $16.5 million after-tax income in AOCI in 2009. In the next twelve months $63.6 million, based on year-end 2009 prices, will be settled and transferred from AOCI to the Consolidated Statements of Income. The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation in the Consolidated Balance Sheets.

	December 31, 2009
	(in millions)
Assets
Fixed-price swaps	$312.6
Option contracts	2.4
Fair value of derivative instruments - short term	$315.0
Fixed-price swaps	$194.3
Option contracts	16.1
Fair value of derivative instruments - long term	$210.4
Liabilities
Fixed-price swaps	$212.7
Basis-only swaps	121.7
Option contracts	2.1
Fair value of derivative instruments - short term	$336.5
Fixed-price swaps	$161.2
Basis-only swaps	117.7
Option contracts	10.9
Fair value of derivative instruments - long term	$289.8

Previously reported basis-only swaps have been combined with fixed-price NYMEX gas swaps for 2010 and 2011 and now qualify as cash flow hedges. The following table sets forth Market Resources' volumes and average net to the well prices for transactions with associated risk management derivative contracts as of December 31, 2009:

Questar E&P Production

Year	Time Periods	Quantity	Average hedge price per Mcf or Bbl, net to the well(a)
			(estimated)
Gas (Bcf) Fixed-price Swaps
2010	12 months	150.9	$5.26
2011	12 months	102.1	4.91
2012	12 months	40.6	5.91
2013	12 months	47.2	5.98
Gas (Bcf) Collars
			Floor- Ceiling
2010	12 months	6.7	$4.65 - $6.51
2011	12 months	27.7	4.63 -   6.66
Oil (Mbbl) Fixed-price Swaps
2010	12 months	913	60.66

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Oil (Mbbl) Collars
			Floor- Ceiling
2010	12 months	730	$47.60 -  $96.10
2011	12 months	1,095	51.73 -  102.10

Energy Trading Marketing Transactions

Year	Time Periods	Quantity	Average price per MMBtu
Gas Sales (millions of MMBtu) Fixed-price Swaps
2010	12 months	7.6	4.83

Gas Purchases (millions of MMBtu) Fixed-price Swaps
2010	12 months	2.8	4.11

(a)

The fixed-price swap and collar prices are reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price.

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 $39.3 million with an interest rate of 0.66% at December 31, 2009 and $89.4 million with an interest rate of 3.39% at December 31, 2008.

All short-term and long-term notes and the term-bank loan are unsecured obligations and rank equally with all other unsecured liabilities. Market Resources' $800.0 million revolving-credit facility had $200.0 million outstanding at a weighted-average interest rate of 0.73% at December 31, 2009. This credit agreement carries an annual commitment fee of 0.115% on the unused balance. At December 31, 2009, Market Resources could pay dividends of $1.1 billion without violating its limitation of total outstanding debt to total capitalization debt covenant.

In August 2009, Market Resources issued $300.0 million of notes due March 2020 with a 6.82% effective interest rate and used the net proceeds to reduce the balance outstanding under its long-term revolving-credit facility. The details of long-term debt are as follows:

	December 31,
	2009	2008
	(in millions)
Revolving-credit facility, 0.73% at December 31, 2009, due 2013	$   200.0	$   450.0
7.50% notes due 2011	150.0	150.0
6.05% notes due 2016	250.0	250.0
6.80% notes due 2018	450.0	450.0
6.80% notes due 2020	300.0
Total long-term debt outstanding	1,350.0	1,300.0
Less unamortized-debt discount	(1.3)	(0.9)
Total long-term debt outstanding	$1,348.7	$1,299.1

Maturities of long-term debt for the five years following December 31, 2009, are $150.0 million in 2011 and $200.0 million in 2013.

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:

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	Year Ended December 31,
	2009	2008	2007
	(in millions)
Federal
Current	$  32.1	($  7.6)	$  56.4
Deferred	124.2	322.9	166.1
State
Current	3.7	(2.8)	1.9
Deferred	3.8	12.4	16.9
Total income tax expense	$163.8	$324.9	$241.3

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,
	2009	2008	2007
Federal income taxes statutory rate	35.0%	35.0%	35.0%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit	1.1	0.7	1.8
Domestic production benefit			(0.3)
Other	(0.5)	(0.4)	(0.1)
Effective income tax rate	35.6%	35.3%	36.4%

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

	December 31,
	2009	2008
	(in millions)
Deferred tax liabilities
Property, plant and equipment	$1,322.1	$1,132.3
Energy-price derivatives		13.6
Total deferred tax liabilities	1,322.1	1,145.9
Deferred tax assets
Energy-price derivatives	29.5
Employee benefits and compensation costs	13.2	7.6
Total deferred tax assets	42.7	7.6
Deferred income taxes - noncurrent	$1,279.4	$1,138.3
Deferred income taxes – current
Energy-price derivatives	$ 8.0	($160.4)
Other	17.6	22.3
Deferred income taxes – current asset (liability)	$25.6	($138.1)

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

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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 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 for the anticipated most likely outcome, and that the amount of the accrual is not material.

On July 10, 2009, Questar E&P filed a petition with the U.S. Tenth Circuit Court of Appeals challenging an administrative compliance order dated May 12, 2009, (Order) issued by the EPA which asserts that Questar E&P's Flat Rock 14P Well and associated equipment is a major source of emissions of hazardous air pollutants and that its operation fails to comply with certain regulations of the CAA. The Order required immediate compliance and threatened substantial penalties for failure to do so. Questar E&P denies that the drilling and operation of the 14P Well and associated equipment violates any provision of the CAA and intends to vigorously defend against this Order.

In October 2009, Questar E&P received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from further discharge of dredged and/or fill material into wetlands of the United States at three well sites without a permit under the Clean Water Act (CWA). The order specifically references prior construction activities at the sites located in Caddo and Red River Parishes, Louisiana. EPA Region 6 has now assumed lead responsibility for enforcement of the pending order and any possible future orders for the removal of unauthorized fills and/or civil penalties under Section 309 of the CWA. The Company is working with the COE and EPA to resolve the matter.

Commitments

Subsidiaries of Market Resources have contracted for firm-transportation services with various third-party pipelines through 2040. Market conditions and competition may prevent full utilization of the contractual capacity. Annual payments and the years covered are as follows:

	(in millions)
2010	$ 17.3
2011	37.2
2012	42.0
2013	40.2
2014	39.3
2015 through 2040	268.0

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 under a sublease agreement that expires January 12, 2012. Rental expense amounted to $4.5 million in 2009, $4.0 million in 2008 and $3.0 million in 2007. 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, 2009, are as follows:

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	(in millions)
2010	$4.8
2011	4.8
2012	4.4
2013	3.0
2014	1.0
2015	1.2

Note 10 – 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 to receive certain benefits from Wexpro's operations. The agreement was approved by the Public Service Commission of Utah 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 20.5%.

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 12.5%.

c. Wexpro sells crude-oil production from oil-producing properties at market prices. Wexpro recovers operating expenses and a return on investment from crude-oil sales. Any residual operating income after recovery of operating expenses and return on investment is shared with Questar Gas receiving 54% and Wexpro retaining 46%. The after-tax rate of return on investments in certain oil-producing properties is adjusted annually and is approximately 12.5%. Wexpro conducts developmental-oil drilling on productive oil properties and bears any costs of dry holes. The after-tax rate of return on investment in developmental-oil properties is adjusted annually and is approximately 17.5%. Questar Gas received oil-income sharing of $1.0 million in 2009, $6.1 million in 2008 and $4.9 million in 2007.

d. Amounts received by Questar Gas from the sharing of Wexpro's oil income are used to reduce natural-gas costs to utility customers.

Wexpro's net investment base and the yearly average rate of return for 2009 and the previous two years are shown in the table below:

	2009	2008	2007
Wexpro's net investment base (in millions)	$431.9	$410.6	$300.4
Average annual rate of return (after tax)	19.9%	19.9%	19.9%

Note 11 – 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. Share-based compensation expense amounted to $13.9 million in 2009 compared with $11.0 million in 2008 and $8.9 million in 2007.

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:

Questar Market Resources 2009 Form 10-K

48

	2009	2008	2007
	Range of Stock Option Variables	Range of Stock Option Variables	Input Variables
Fair value of options at grant date	$31.06 - $35.38	$28.58 - $53.83	$41.08
Risk-free interest rate	1.78% - 2.51%	2.72% - 3.20%	4.77%
Expected price volatility	28.1% - 29.9%	20.3% - 32.3%	22.4%
Expected dividend yield	1.39% - 1.61%	0.91 - 1.72%	1.14%
Expected life in years	5.0 - 5.0	5.0 - 5.0	5.2

Unvested stock options increased by 370,495 shares to 917,995 in 2009. Stock-option transactions under the terms of the LTSIP for the three years ended December 31, 2009, are summarized below:

	Options Outstanding	Price Range	Weighted- Average Price
Balance at January 1, 2007	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
Granted	528,000	35.38	35.38
Exercised	(169,956)	7.50 –   14.01	10.44
Employee transferred	6,000	11.48 –   13.56	13.21
Forfeited	(60,000)	28.58 –   35.38	29.15
Balance at December 31, 2009	1,774,494	$7.50 - $41.08	$25.29

	Options Outstanding			Options Exercisable		Unvested Options
Range of exercise prices	Number outstanding at Dec. 31, 2009	Weighted-average remaining term in years	Weighted-average exercise price	Number exercisable at Dec. 31, 2009	Weighted-average exercise price	Number unvested at Dec. 31, 2009	Weighted-average exercise price
$7.50	23,000	0.1	$  7.50	23,000	$  7.50
$11.48 – $11.98	367,842	2.1	11.71	367,842	11.71
$13.56 – $14.01	353,878	2.7	13.64	353,878	13.64
$17.55 – $28.58	246,774	5.7	27.94	91,779	26.86	154,995	$28.58
$35.38 – $41.08	783,000	5.2	36.63	20,000	41.08	763,000	$36.51
	1,774,494	4.1	$25.29	856,499	$14.70	917,995	$35.18

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, 2009, was 14 months. Transactions involving restricted shares under the terms of the LTSIP for the three years ended December 31, 2009, are summarized below:

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	Restricted Shares Outstanding	Price Range	Weighted-Average Price
Balance at January 1, 2007	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
Granted	212,300	29.30 –   36.88	35.12
Distributed	(207,704)	25.12 –   70.13	39.68
Employee transferred	966	25.50 –   53.83	43.89
Forfeited	(32,054)	35.23 –   62.50	47.74
Balance at December 31, 2009	573,185	$25.12 – $70.13	$44.53

Note 12 – 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 nonqualified 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 $5.3 million in 2009, $3.8 million in 2008 and $4.6 million in 2007.

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, 2009 and 2008, 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 $1.5 million in 2009, $1.3 million in 2008 and 2007, respectively.

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, 2009 and 2008, 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

Questar Market Resources 2009 Form 10-K

50

of 6% of their qualifying earnings. In addition, the Company contributes $200 annually to the EIP for each eligible employee. The EIP trustee purchases Questar shares on the open market with cash received. The Company recognizes expense equal to its yearly contributions, which amounted to $4.4 million in 2009, $4.1 million in 2008 and $3.5 million in 2007.

Note 13 – Related Party Transactions

Market Resources receives a portion of its revenues from services provided to affiliate, Questar Gas. The Company received $249.4 million in 2009, $232.8 million in 2008 and $171.6 million in 2007 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 10).

Market Resources pays Questar for certain administrative services. These payments were included in operating expenses and amounted to $19.9 million in 2009, $10.7 million in 2008 and $16.8 million in 2007. 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 2009, $2.1 million in 2008 and $2.8 million in 2007 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 2009, $1.1 million in 2008 and $1.0 million in 2007.

The Company loaned cash to affiliated companies and received interest income of $0.1 million in 2009, $0.5 million in 2008, and $4.5 million in 2007. Market Resources borrowed cash from affiliated companies and was charged interest expense of $0.3 million in 2009, $3.8 million in 2008 and $6.8 million in 2007.

Note 14 – 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)
2009
Revenues
From unaffiliated customers	$1,949.0		$1,267.3	$  17.8		$238.3		$425.6
From affiliated companies	249.5	($386.9)		225.1		26.3		385.0
Total Revenues	2,198.5	(386.9)	1,267.3	242.9		264.6		810.6
Operating expenses
Cost of natural gas and other products sold	411.1	(379.5)						790.6
Operating and maintenance	222.8	(2.1)	127.5	21.2		75.0		1.2
General and administrative	108.6	(5.3)	68.0	17.0		25.0		3.9
Production and other taxes	82.9		58.3	20.0		4.6
Depreciation, depletion and amortization	617.9		512.8	58.8		44.3		2.0
Other operating expenses	46.3		45.3	1.0
Total operating expenses	1,489.6	(386.9)	811.9	118.0		148.9		797.7
Net gain (loss) from asset sales	1.2		1.6	(0.3)		(0.1)
Operating income	710.1		457.0	124.6		115.6		12.9
Interest and other income	(182.6)	(71.4)	(185.7)	3.2		(0.2)		71.5
Income from unconsolidated affiliates	2.7		0.1			2.6

Questar Market Resources 2009 Form 10-K

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Interest expense	(70.3)	71.4	(63.9)	(0.9)		(6.0)		(70.9)
Income tax expense	(163.8)		(72.6)	(46.2)		(40.0)		(5.0)
Net income	296.1		134.9	80.7		72.0		8.5
Net income attributable to noncontrolling interest	(2.6)					(2.6)
Net attributable to Market Resources	$  293.5		$  134.9	$  80.7		$  69.4		$   8.5
Identifiable assets	$6,419.4		$4,628.3	$649.6		$928.6		$212.9
Investment in unconsolidated affiliates	43.9					43.9
Cash capital expenditures	1,314.6		1,108.6	116.2		88.3		1.5
Accrued capital expenditures	1,218.5		1,033.7	110.1		73.3		1.4
Goodwill	60.1		60.1
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
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 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
Cash capital expenditures	2,280.5		1,777.3	143.8		357.9		1.5
Accrued capital expenditures	2,405.1		1,864.2	144.8		394.5		1.6
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

Questar Market Resources 2009 Form 10-K

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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	$   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
Cash capital expenditures	943.9		708.5		105.0		128.3		2.1
Accrued capital expenditures	964.3		724.8		109.4		128.1		2.0
Goodwill	60.9		60.9

Note 15 –Quarterly Financial Information (Unaudited)

A reclassification of first, second and third quarter 2009 revenues and realized loss on basis-only swaps increased both line items by $3.4 million, $4.6 million and $7.2 million, respectively. Following is a summary of unaudited quarterly financial information:

	First	Second	Third	Fourth
	Quarter	Quarter	Quarter	Quarter	Year
	(in millions)
2009
Revenues	$541.8	$495.6	$541.9	$619.2	$2,198.5
Operating income	184.0	148.5	179.0	198.6	710.1
Net income	21.2	65.3	92.6	117.0	296.1
Net income attributable to Market Resources	20.7	64.7	92.0	116.1	293.5
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	141.7	164.2	200.0	88.6	594.5
Net income attributable to Market Resources	139.3	162.1	197.6	86.5	585.5

Note 16 – Supplemental Gas and Oil Information (Unaudited)

The Company is making the following supplemental disclosures of gas and oil producing activities, in accordance with ASC 932 "Extractive Activities - Oil and Gas" as amended by ASU 2010-03 "Oil and Gas Reserve Estimation and Disclosures" and SEC Regulation S-X.

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.

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:

Questar Market Resources 2009 Form 10-K

53

	December 31,
	2009	2008
	(in millions)
Proved properties	$5,721.5	$ 4,948.2
Unproved properties	389.6	193.2
	6,111.1	5,141.4
Accumulated depreciation, depletion and amortization	(1,890.9)	(1,421.8)
Net capitalized costs	$4,220.2	$ 3,719.6

Costs Incurred

The costs incurred in gas and oil exploration and development activities are displayed in the table below. The costs incurred to develop proved undeveloped reserves were $216.1 million in 2009, $219.9 million in 2008 and $125.8 million in 2007.

	Year Ended December 31,
	2009	2008	2007
	(in millions)
Property acquisition
Unproved	$  215.1	$   167.3	$   28.9
Proved	6.4	602.7	45.1
Exploration (capitalized and expensed)	92.9	58.7	14.9
Development	741.1	1,061.2	652.2
Total costs incurred	$1,055.5	$1,889.9	$741.1

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,
	2009	2008	2007
	(in millions)
Revenues	$1,267.3	$1,392.1	$956.0
Production costs	185.8	229.4	148.0
Exploration expenses	25.0	29.3	22.0
Depreciation, depletion and amortization	512.8	330.9	243.5
Abandonment and impairment	20.3	44.6	10.8
Total expenses	743.9	634.2	424.3
Revenues less expenses	523.4	757.9	531.7
Income taxes	(183.2)	(269.1)	(197.3)
Results of operation from producing activities excluding corporate   overhead and interest expenses	$  340.2	$  488.8	$334.4

Estimated Quantities of Proved Gas and Oil Reserves

Estimates of proved gas and oil reserves have been completed in accordance with professional engineering standards and the Company's established internal controls, which includes the compliance oversight of a multi-functional reserves review committee responsible to the Company's board of directors. Questar E&P's estimated proved reserves have been prepared by Ryder Scott Company, L.P., independent reservoir engineering consultants, in accordance with the SEC's Regulation S-X and ASC 932 as amended. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation.

Questar Market Resources 2009 Form 10-K

54

			Natural Gas
	Natural Gas	Oil and NGL	Equivalents
	(Bcf)	(MMbbl)	(Bcfe)
Proved Reserves
Balance at January 1, 2007	1,461.2	28.4	1,631.4
Revisions -
Previous estimates	26.3	3.3	46.2
Pinedale increased-density(a)	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(a)	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
Revisions - previous estimates	(318.9)	3.4	(298.8)
Extensions and discoveries(a)	982.4	5.4	1,014.6
Purchase of reserves in place	1.7	0.1	2.5
Production	(168.7)	(3.5)	(189.5)
Balance at December 31, 2009	2,525.0	37.0	2,746.9
Proved Developed Reserves
Balance at January 1, 2007	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
Balance at December 31, 2009	1,178.7	27.4	1,342.8
Proved Undeveloped Reserves
Balance at January 1, 2007	609.2	5.3	640.7
Balance at December 31, 2007	681.1	6.5	720.2
Balance at December 31, 2008	900.4	8.0	948.7
Balance at December 31, 2009	1,346.3	9.6	1,404.1

(a) 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 the development and application of reliable technologies. The continued analysis of new data has led to progressive increases in estimates of original gas-in-place at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. With the application of the amendments of ASC 932 in ASU 2010-03, reserves associated with Pinedale increased density drilling are included in extensions and discoveries for the year ended December 31, 2009, because each new well drilled recovers incremental reserves that would otherwise be unrecoverable.

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55

	2009
	(Bcfe)
Proved undeveloped reserves at January 1,	948.7
Transferred to proved developed reserves	(124.4)
Revisions-previous estimates(a)	(217.2)
Extensions and discoveries(b)	797.0
Proved undeveloped reserves at December 31, (c)	1,404.1

(a)Revisions include price-related reductions of 220.4 Bcfe. Year-end 2009 proved reserve estimates were based on SEC-prescribed 12-month average prices of $3.06 per Mcf and $45.54 per barrel. Such price-related reductions would not have occurred under the SEC's prior end-of-year pricing rules.

(b)Extensions and discoveries include 578.1 Bcfe resulting from the application of the amendments of ASC 932 in ASU 2010-03 relative to booking proved undeveloped reserves for locations more than one location away from an existing producing well when reliable technology can be demonstrated. Such additions are based on empirical data including subsurface well control, long-term well performance, pressure testing and pressure studies, core data, and ongoing pilot programs of increased density development, which have confirmed with reasonable certainty the areal extent and continuity of the subject hydrocarbon accumulations. The Company routinely applies multi-stage hydraulic fracture stimulation technology and in some instances horizontal drilling combined with multi-stage fracture stimulation technology in development of its reserves. Empirical data has also been incorporated in detailed reservoir models supported by three dimensional seismic data and numerical simulation studies to further corroborate such conclusions.

(c)All of Questar E&P's proved undeveloped reserves at December 31, 2009, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves, except for 350 Bcfe located within the northernmost portion of the Company's Pinedale Anticline leasehold in western Wyoming. As discussed in Item 1of Part I of this Annual Report, long-term development of natural gas reserves in the PAPA is governed by the BLM's September 2008, ROD on the FSEIS. Under the ROD, Questar E&P and Wexpro are allowed to drill and complete wells year-round in designated concentrated development areas defined in the PAPA. The ROD contains additional requirements and restrictions on the sequence of development of the PAPA, which requires the Company to develop its leasehold from the south to the north. These restrictions result in protracted, phased development of the PAPA that is beyond the control of the Company. The Company has an ongoing development plan for the PAPA and the financial capability to continue development in the manner estimated.

Standardized Measure of Future Net Cash Flows Relating to Proved Reserves

Future net cash flows were calculated at December 31, 2009, by applying prices used in estimating 2009 reserves, which was the simple average of the first-of-the-month prices for the twelve months of 2009 with consideration of known contractual price changes. Future net cash flow calculations for years prior to 2009 used year-end prices and known contract-price changes. The prices used do not include any impact of hedging activities. The average price per Mcf used to calculate proved natural gas reserves was $3.06 in 2009, $4.62 in 2008 and $6.01 in 2007. The average price per barrel of proved oil and NGL reserves combined used to calculate reserves was $45.54 in 2009, $28.41 in 2008 and $80.86 in 2007. 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 $436.8 million in 2010, $467.9 million in 2011 and $389.1 million in 2012. At the end of the five-year period ending in 2014, the Company expects to have evaluated 100% of the current 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. The standardized measure of future net cash flows relating to proved reserves is presented in the table below:

Questar Market Resources 2009 Form 10-K

56

	Year Ended December 31,
	2009	2008		2007
	(in millions)
Future cash inflows	$9,419.3	$10,263.4	$12,704.3
Future production costs	(2,841.8)	(2,717.6)	(2,863.4)
Future development costs	(2,252.7)	(1,884.0)	(1,232.4)
Future income tax expenses	(674.0)	(1,241.3)	(2,668.8)
Future net cash flows	3,650.8	4,420.5	5,939.7
10% annual discount for estimated timing of net cash flows	(2,207.8)	(2,418.6)	(3,105.7)
Standardized measure of discounted future net cash flows	$1,443.0	$  2,001.9	$ 2,834.0

The principal sources of change in the standardized measure of future net cash flows relating to proved reserves is presented in the table below:

	Year Ended December 31,
	2009	2008	2007
	(in millions)
Balance at January 1,	$2,001.9	$2,834.0	$1,567.8
Sales of gas and oil produced during the period, net of production costs	(1,081.5)	(1,162.7)	(808.0)
Net change in prices and production costs related to future production	(813.1)	(1,306.1)	1,554.6
Net change due to extensions and discoveries	1,291.6	438.7	523.6
Net change due to revisions of quantity estimates	(380.4)	16.3	470.0
Net change due to purchases and sales of reserves in place	6.4	499.9	41.8
Previously estimated development costs incurred during the period	216.1	219.9	125.8
Changes in future development costs	(347.4)	(662.6)	(214.5)
Accretion of discount	256.4	410.7	221.0
Net change in income taxes	295.8	711.2	(635.0)
Other	(2.8)	2.6	(13.1)
Net change	(558.9)	(832.1)	1,266.2
Balance at December 31,	$1,443.0	$2,001.9	$2,834.0

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 of Cost-of-Service Activities

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

	December 31,
	2009	2008
	(in millions)
Wexpro	$593.9	$536.6
Questar Gas	10.4	11.2
Total capitalized costs of cost-of-service activities	$604.3	$547.8

Questar Market Resources 2009 Form 10-K

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Costs Incurred for Cost-of-Service Activities

Costs incurred by Wexpro for cost-of-service gas and oil-producing activities were $113.2 million in 2009, $148.0 million in 2008 and $110.7 million in 2007.

Results of Operation of Cost-of-Service Activities

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,
	2009	2008	2007
	(in millions)
Revenues
From unaffiliated companies	$  17.8	$  31.1	$  21.6
From affiliates(a)	225.1	209.9	155.7
Total revenues	242.9	241.0	177.3
Production costs	42.2	67.3	41.4
Depreciation, depletion and amortization	58.8	48.5	31.2
Total expenses	101.0	115.8	72.6
Revenues less expenses	141.9	125.2	104.7
Income taxes	(51.7)	(44.9)	(35.2)
Results of operation for cost-of-service producing activities excluding     corporate overhead and interest expenses	$  90.2	$  80.3	$  69.5

(a) Primarily represents revenues including reimbursement of general and administrative expenses amounting to $16.7 million in 2009, $13.3 million in 2008 and $14.4 million in 2007 received from Questar Gas pursuant to the Wexpro Agreement.

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

Estimates of cost-of-service proved gas and oil reserves have been prepared in accordance with professional engineering standards and the Company's established internal controls, which includes the compliance oversight of a multi-functional reserves review committee that reports to the Company's board of directors. The estimates set forth below were prepared by Wexpro's reservoir engineers, individuals who possess professional qualifications and demonstrated competency in reserves estimation and evaluation.

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 acknowledges this potential circumstance 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.

			Natural Gas
	Natural Gas	Oil and NGL	Equivalents
	(Bcf)	(MMbbl)	(Bcfe)
Proved Reserves
Balance at January 1, 2007	620.6	4.4	647.0
Revisions-
Previous estimates	(29.9)		(30.0)
Pinedale increased-density(a)	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(a)	65.1	0.5	68.2

Questar Market Resources 2009 Form 10-K

58

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
Revisions - previous estimates	(27.3)	(0.2)	(28.3)
Extensions and discoveries	78.0	0.6	81.4
Production	(48.2)	(0.4)	(50.7)
Balance at December 31, 2009	649.4	4.5	676.3
Proved Developed Reserves
Balance at January 1, 2007	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
Balance at December 31, 2009	477.1	3.1	495.5
Proved Undeveloped Reserves
Balance at January 1, 2007	180.0	1.5	188.8
Balance at December 31, 2007	176.5	1.4	185.0
Balance at December 31, 2008	175.5	1.4	184.0
Balance at December 31, 2009	172.3	1.4	180.8

(a)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 the development and application of reliable technologies. The continued analysis of new data has led to progressive increases in estimates of original gas-in-place at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. With the application of the amendments of ASC 932 in ASU 2010-03, reserves associated with Pinedale increased density drilling are included in extensions and discoveries for the year ended December 31, 2009, because each new well drilled recovers incremental reserves that would otherwise be unrecoverable.

Financial Statement Schedule:

QUESTAR MARKET RESOURCES, INC.
Schedule of Valuation and Qualifying Accounts
				Column D
		Column C		Deductions for
Column A Description	Column B Beginning Balance	Amounts charged to expense		accounts written off and other	Column E Ending Balance
(in millions)
Year-Ended December 31, 2009
Allowance for bad debts	$2.7		$0.4	($0.1)	$3.0
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

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

The Company has not changed its independent auditors or had any disagreement with them concerning accounting matters and financial statement disclosures within the last 24 months.

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59

ITEM 9A(T).  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 December 31, 2009. Based on such evaluation, such officers have concluded that, as of December 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 December 31, 2009, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Management's Assessment of Internal Control Over Financial Reporting

Market Resources' management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(e). Market Resources' management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2009. The criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework were used to make this assessment. We believe that the Company's internal control over financial reporting as of December 31, 2009, is effective based on those criteria.

This Annual Report does not include an attestation report of the Company's registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the Company's registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management's report in this Annual Report.

ITEM 9B.  OTHER INFORMATION.

None.

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERANCE (Omitted).

ITEM 11.  EXECUTIVE COMPENSATION (Omitted).

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS (Omitted).

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE (Omitted).

The Company, as a wholly owned subsidiary of a reporting company under the Act, is entitled to omit all information requested in Part III, Items 10-13.

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES.

Ernst & Young LLP serves as the independent registered public accounting firm for Questar and its subsidiaries including the Company. The following table lists the fees billed by Ernst & Young to Questar for services and the fees billed directly to the Company or allocated to the Company as a member of Questar's consolidated group:

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60

	2009	2008
Audit Fees	$1,217,596	$1,309,254
Market Resources Portion	688,484	734,782
Audit-related Fees	106,221	100,000
Market Resources Portion	35,722	49,779
Tax Fees	8,000	3,570
Market Resources Portion	6,692	2,129
All Other Fees	194,027	237,879
Market Resources Portion	149,163	184,484

PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

Financial statements and financial statement schedules filed as part of this report are listed in the index included in Item 8. Financial Statements and Supplementary Data of this report.

(b) Exhibits. The following is a list of exhibits required to be filed as a part of this report in Item 15(b).

Exhibit No.

Description

  1.1.*

Purchase Agreement, dated May 11, 2006, by and among Questar Market Resources, Inc., and named Underwriters. (Exhibit No. 99.1 to the Company's Current Report on Form 8-K dated May 11, 2006.)

  1.2.*

Purchase Agreement, dated April 1, 2008, by and among Questar Market Resources Inc., and the Underwriters named on Schedule A thereto. (Exhibit No. 1.1. to the Company's Current Report on Form 8-K dated April 1, 2008.)

  3.1.*

Articles of Incorporation dated April 27, 1988, for Utah Entrada Industries, Inc. (Exhibit No. 3.1. to the Company's Form 10 dated April 12, 2000.)

  3.2.*

Articles of Merger dated May 20, 1988, of Entrada Industries, Inc., a Delaware corporation and Utah Entrada Industries, Inc, a Utah corporation. (Exhibit No. 3.2. to the Company's Form 10 dated April 12, 2000.)

  3.3.*

Articles of Amendment dated August 31, 1998, changing the name of Entrada Industries, Inc. to Questar Market Resources, Inc. (Exhibit No. 3.3. to the Company's Form 10 dated April 12, 2000.)

  3.4.*

Bylaws, as amended effective February 8, 2005, (Exhibit No. 3.4. to the Company's Annual Report on Form 10-K for 2004.)¹

  4.1.*¹

Indenture dated as of March 1, 2001, between Questar Market Resources, Inc. and Bank One, NA, as Trustee for the Company's Notes. (Exhibit No. 4.01. to the Company's Current Report on Form 8-K dated March 6, 2001.)

  4.2.*

Credit Agreement dated March 19, 2004, by and among the Company, Bank of America, N.A. and other lenders. (Exhibit No. 4.4. to the Company's Annual Report on Form 10-K for 2003.)

  4.3.*

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

  4.4.*

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

  4.5.*

Term Credit Agreement dated February 15, 2008, by and among the Company and Bank of America, N.A. (Exhibit 4.5 to the Company's Annual Report on Form 10-K for 2007,)

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61

  4.6.*

Credit Agreement dated March 11, 2008, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 4.1. to the Company's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2008.)

10.1.*

Stipulation and Agreement dated October 14, 1981, executed by Mountain Fuel Supply Company [Questar Gas Company]; Wexpro Company; the Utah Department of Business Regulations, Division of Public Utilities; the Utah Committee of Consumer Services; and the staff of the Public Service Commission of Wyoming. (Exhibit No. 10(a) to Questar Gas Company's Annual Report on Form 10-K for 1981.)

10.2.*

First Amendment to Credit Agreement dated October 25, 2004, by and among the Company, Bank of America, N.A. and other lenders. (Exhibit No. 4.5. to the Company's Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2004.)

10.3.*

Second Amendment to Credit Agreement dated August 9, 2005, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 4.4. to the Company's Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005.)

10.4.*

Third Amendment to Credit Agreement dated September 20, 2005, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 4.5. to the Company's Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005.)

10.5.*

Fourth Amendment to Credit Agreement dated July 27, 2006, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 10.1 to the Company's Quarterly Report on Form 10-Q for Quarter Ended June 30, 2006.)

10.6.*

Fifth Amendment to Credit Agreement dated July 25, 2007, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 10.1 to the Company's Quarterly Report on Form 10-Q for Quarter Ended June 30, 2007.)

10.7.*

Purchase and Sale Agreement dated January 25, 2008, by and among Will-Drill Resources, Inc. and other sellers party thereto and Questar Exploration and Production Company. (Exhibit No. 10.1 to the Company's Current Report on Form 8-K dated February 29, 2008.)

10.8.*

Purchase Agreement, dated August 24, 2009, by and among Questar Market Resources Inc., and the Underwriters. (Exhibit No. 1.1 to the Company's Form 8-K dated August 24, 2009).

12.

Ratio of earnings to fixed charges.

23.2

Consent of Independent Petroleum Engineers and Geologists.

23.3

Qualifications and Report of Independent Petroleum Engineers and Geologists.

24.

Power of Attorney.

31.1.

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

31.2.

Certification signed by Richard J. Doleshek, Questar Market Resources, Inc. Executive Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.

Certification signed by Charles B. Stanley and Richard J. Doleshek, Questar Market Resources, Inc. President and Chief Executive Officer and Executive Vice President and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

¹Wells Fargo Bank, N.A. serves as the successor trustee.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, on the 5th day of March, 2010.

QUESTAR MARKET RESOURCES, INC.

   (Registrant)

By:  

/s/C. B. Stanley

            

C. B. Stanley

            

President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/C. B. Stanley

President and Chief Executive Officer

C. B. Stanley

Director (Principal Executive Officer)

/s/Richard J. Doleshek

Executive Vice President and

Richard J. Doleshek

Chief Financial Officer (Principal Financial Officer)

/s/B. Kurtis Watts

Vice President and Controller

B. Kurtis Watts

(Principal Accounting Officer)

*Keith O. Rattie

Chairman of the Board; Director

*Phillips S. Baker, Jr.

Director

*Teresa Beck

Director

*R. D. Cash

Director

*L. Richard Flury

Director

*James A. Harmon

Director

*Robert E. McKee III

Director

*M. W. Scoggins

Director

*C. B. Stanley

Director

March 5, 2010

*By

/s/C. B. Stanley

           Date

C. B. Stanley, Attorney in Fact

Exhibits List

Exhibit No.

Description

  1.1.*

Purchase Agreement, dated May 11, 2006, by and among Questar Market Resources, Inc., and named Underwriters. (Exhibit No. 99.1 to the Company's Current Report on Form 8-K dated May 11, 2006.)

  1.2.*

Purchase Agreement, dated April 1, 2008, by and among Questar Market Resources Inc., and the Underwriters named on Schedule A thereto. (Exhibit No. 1.1. to the Company's Current Report on Form 8-K dated April 1, 2008.)

  3.1.*

Articles of Incorporation dated April 27, 1988, for Utah Entrada Industries, Inc. (Exhibit No. 3.1. to the Company's Form 10 dated April 12, 2000.)

  3.2.*

Articles of Merger dated May 20, 1988, of Entrada Industries, Inc., a Delaware corporation and Utah Entrada Industries, Inc, a Utah corporation. (Exhibit No. 3.2. to the Company's Form 10 dated April 12, 2000.)

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63

  3.3.*

Articles of Amendment dated August 31, 1998, changing the name of Entrada Industries, Inc. to Questar Market Resources, Inc. (Exhibit No. 3.3. to the Company's Form 10 dated April 12, 2000.)

  3.4.*

Bylaws, as amended effective February 8, 2005, (Exhibit No. 3.4. to the Company's Annual Report on Form 10-K for 2004.)

¹

  4.1.*¹

Indenture dated as of March 1, 2001, between Questar Market Resources, Inc. and Bank One, NA, as Trustee for the Company's Notes. (Exhibit No. 4.01. to the Company's Current Report on Form 8-K dated March 6, 2001.)

  4.2.*

Credit Agreement dated March 19, 2004, by and among the Company, Bank of America, N.A. and other lenders. (Exhibit No. 4.4. to the Company's Annual Report on Form 10-K for 2003.)

  4.3.*

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

  4.4.*

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

  4.5.*

Term Credit Agreement dated February 15, 2008, by and among the Company and Bank of America, N.A. (Exhibit 4.5 to the Company's Annual Report on Form 10-K for 2007,)

  4.6.*

Credit Agreement dated March 11, 2008, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 4.1. to the Company's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2008.)

10.1.*

Stipulation and Agreement dated October 14, 1981, executed by Mountain Fuel Supply Company [Questar Gas Company]; Wexpro Company; the Utah Department of Business Regulations, Division of Public Utilities; the Utah Committee of Consumer Services; and the staff of the Public Service Commission of Wyoming. (Exhibit No. 10(a) to Questar Gas Company's Annual Report on Form 10-K for 1981.)

10.2.*

First Amendment to Credit Agreement dated October 25, 2004, by and among the Company, Bank of America, N.A. and other lenders. (Exhibit No. 4.5. to the Company's Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2004.)

10.3.*

Second Amendment to Credit Agreement dated August 9, 2005, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 4.4. to the Company's Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005.)

10.4.*

Third Amendment to Credit Agreement dated September 20, 2005, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 4.5. to the Company's Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005.)

10.5.*

Fourth Amendment to Credit Agreement dated July 27, 2006, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 10.1 to the Company's Quarterly Report on Form 10-Q for Quarter Ended June 30, 2006.)

10.6.*

Fifth Amendment to Credit Agreement dated July 25, 2007, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 10.1 to the Company's Quarterly Report on Form 10-Q for Quarter Ended June 30, 2007.)

10.7.*

Purchase and Sale Agreement dated January 25, 2008, by and among Will-Drill Resources, Inc. and other sellers party thereto and Questar Exploration and Production Company. (Exhibit No. 10.1 to the Company's Current Report on Form 8-K dated February 29, 2008.)

10.8.*

Purchase Agreement, dated August 24, 2009, by and among Questar Market Resources Inc., and the Underwriters. (Exhibit No. 1.1 to the Company's Form 8-K dated August 24, 2009).

12.

Ratio of earnings to fixed charges.

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23.2

Consent of Independent Petroleum Engineers and Geologists.

23.3

Qualifications and Report of Independent Petroleum Engineers and Geologists.

24.

Power of Attorney.

31.1.

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

31.2.

Certification signed by Richard J. Doleshek, Questar Market Resources, Inc. Executive Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.

Certification signed by Charles B. Stanley and Richard J. Doleshek, Questar Market Resources, Inc. President and Chief Executive Officer and Executive Vice President and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

¹Wells Fargo Bank, N.A. serves as the successor trustee.

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