Edgar Filing: QUESTAR MARKET RESOURCES INC

UNITED STATES

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, 2007

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QUESTAR MARKET RESOURCES, INC.

(Exact name of registrant as specified in charter)

STATE OF UTAH

0-30321

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)

(801) 324-2600

(Registrant’s telephone number)

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 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

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

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

Yes [ ] No [X]

Aggregate market value of the voting common equity held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second quarter (June 30, 2007): $0.

On January 31, 2008, 4,309,427 shares of the registrant’s common stock, $1.00 par value, were outstanding (all shares are owned by Questar Corporation).

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

QUESTAR MARKET RESOURCES 2007 FORM 10-K

TABLE OF CONTENTS

Page No.

Where You Can Find More Information

Forward-Looking Statements

Glossary of Commonly Used Terms

PART I

Item 1.

BUSINESS

Nature of Business

Exploration and Production

Questar E&P

Wexpro

Midstream Field Services – Questar Gas Management

Energy Marketing – Questar Energy Trading

Environmental Matters

Employees

Item 1A.

RISK FACTORS

Item 1B.

UNRESOLVED STAFF COMMENTS

Item 2.

PROPERTIES

Exploration and Production

Questar E&P

Wexpro

Midstream Field Services – Questar Gas Management

Energy Marketing – Questar Energy Trading

Item 3.

LEGAL PROCEEDINGS

Item 4.

SUBMISSION OF MATTERS TO A VOTE OF

SECURITY HOLDERS (omitted)

PART II

Item 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED

STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY

SECURITIES

Item 6.

SELECTED FINANCIAL DATA (omitted)

Item 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATION

Item 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT

MARKET RISK

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

Item 9A(T).

CONTROLS AND PROCEDURES

Item 9B.

OTHER INFORMATION

PART III

Item 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

(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)

Item 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

PART IV

Item 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

SIGNATURES

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). The public may read and copy these reports and any other materials filed with the SEC at its Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549-0213. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC also maintains a web site that contains information filed electronically that can be accessed over the Internet at www.sec.gov.

Interested parties can also access financial and other information via Questar’s 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. Questar’s web site also contains Statements of Responsibility for Board Committees, Corporate Governance Guidelines and the Business Ethics and Compliance Policy.

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

Forward-Looking Statements

This 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,

QUESTAR MARKET RESOURCES 2007 FORM 10-K

prospective services or products, future performance or results of current and anticipated services or products, exploration efforts, expenses, the outcome of contingencies such as legal proceedings, trends in operations and financial results.

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

the risk factors discussed in Part I, Item 1A of 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.

Glossary of Commonly Used Terms

Billion.

bbl

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

basis

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

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

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

cfe

Cubic feet of natural gas equivalents.

development well

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

dewpoint

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

dry hole

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

dth

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

QUESTAR MARKET RESOURCES 2007 FORM 10-K

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.

futures contract

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

gal

U.S. gallon.

gas

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

gross

“Gross” natural gas and oil wells or “gross” acres 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.

infill development drilling

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

lease operating expenses

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

Thousand.

Million.

natural gas equivalents

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

natural gas liquids (NGL)

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

net

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

net revenue interest

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

proved reserves

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

proved developed reserves

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

proved developed producing reserves

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

proved undeveloped reserves

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

QUESTAR MARKET RESOURCES 2007 FORM 10-K

reservoir

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

royalty

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

seismic

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

wet gas

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

working interest

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

workover

Operations on a producing well to restore or increase production.

FORM 10-K

ANNUAL REPORT, 2007

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:

QUESTAR MARKET RESOURCES 2007 FORM 10-K

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See Note 12 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.

Exploration and Production – Questar E&P and Wexpro

General: Market Resources’ exploration and production business is conducted through Questar E&P and Wexpro. Exploration and production generated approximately 83% of the Company’s operating income in 2007. Questar E&P operates in two core areas – the Rocky Mountain region of Wyoming, Utah and Colorado 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, in the Uinta Basin of Utah and in the Elm Grove area of northwestern Louisiana. Questar E&P continues to conduct exploratory drilling to determine the commerciality of its inventory of undeveloped leaseholds located primarily in the Rocky Mountain region. 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 1,867.6 Bcfe of estimated proved reserves as of December 31, 2007. Approximately 80% of Questar E&P’s proved reserves, or 1,493.7 Bcfe, were located in the Rocky Mountain region of the United States, while the remaining 20%, or 373.9 Bcfe, were located in the Midcontinent region. Approximately 1,147.4 Bcfe of the proved reserves reported by Questar E&P at year-end 2007 were developed, while 720.2 Bcfe were proved undeveloped. The majority of the proved undeveloped reserves were associated with the Company’s Pinedale Anticline leasehold. Natural gas comprised about 89% of Questar E&P’s total proved reserves at year-end 2007. See Item 2 of Part I and Note 15 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company’s proved reserves.

Wexpro develops and produces gas and oil on certain properties for affiliate Questar Gas under the terms of a long-standing comprehensive agreement with the states of Utah and Wyoming, the Wexpro Agreement. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19-20% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation – its investment base. The term of the Wexpro Agreement coincides with the productive life of the gas and oil properties covered therein. Wexpro’s investment

QUESTAR MARKET RESOURCES 2007 FORM 10-K

base totaled $300.4 million at December 31, 2007. See Note 11 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 34% of Questar Gas supply requirements during 2007 at prices that were significantly lower than Questar Gas paid for purchased gas. Wexpro owns oil-producing properties. Under terms of the Wexpro Agreement, revenues from crude-oil sales offset operating expenses and provide Wexpro with a return on its investment. Any remaining revenues, after recovery of expenses and Wexpro’s return on investment, are divided between Wexpro (46%) and Questar Gas (54%).

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 unlocked 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 reserves and leases. 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. Competition is particularly intense when prices are high, as has been the case in recent years.

Questar E&P, through Energy Trading, sells natural gas production to a variety of customers, including gas-marketing firms, industrial users and local-distribution companies. It regularly evaluates counterparty credit and may require financial guarantees from parties that fail to meet its credit criteria.

Wexpro collected 88% of its 2007 revenues from affiliated companies, primarily Questar Gas.

Regulation: Exploration and production 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; 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 leases in the Rocky Mountain area are 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 portions of both Market Resources leaseholds due to wildlife activity and/or habitat. Development of Pinedale leasehold acreage is subject to the terms of certain winter-drilling restrictions. In 2004, Market Resources worked with federal and state officials in Wyoming to obtain authorization for limited winter-drilling activities 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 Market Resources 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 Market Resources on public lands. The BLM is currently preparing a Supplemental Environmental Impact Statement (SEIS) to consider expanded winter-drilling and completion operations on the Pinedale Anticline. The BLM’s Record of Decision on the SEIS, expected in mid-2008, could significantly impact the pace of development on the Market Resources acreage.

Midstream Field Services – Questar Gas Management

General: Gas Management and its partnerships, generated approximately 13% of the Company’s operating income in 2007. Gas Management owns 50% 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 Kern River Gas Transmission Co.’s Muddy Creek compressor station.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Fee-based gathering and processing revenues were 74% of Gas Management’s net operating revenues during 2007. Approximately 31% of Gas Management’s 2007 net gas-processing revenues were derived from fee-based processing agreements. The remaining revenues were derived from natural gas processing margins that are in part exposed to the frac spread. To reduce processing margin risk, Gas Management has restructured many of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. A keep-whole contract insulates producers from frac-spread risk while a fee-based contract eliminates commodity price risk for the processing-plant owner. 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.

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. It combines gas volumes purchased from third parties and equity production 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. Energy Trading generated approximately 4% of the Company’s operating income in 2007.

Competition and Customers: Energy Trading sells equity 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 to storage, refining or pipeline facilities. Energy Trading uses derivatives to manage commodity price risk. Energy Trading primarily uses fixed-price swaps to secure a known price for a specific volume of production. Energy Trading does not engage in speculative hedging transactions. See Notes 1 and 6 to the consolidated financial statements included in Item 8 and Item 7A of Part II of this Annual Report for additional information relating to hedging activities.

Environmental Matters

A discussion of Market Resources’ environmental matters is included in Item 3 of Part I of this Annual Report.

Employees

At December 31, 2007, Market Resources had 775 employees compared with 679 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, revenues, operating results, cash flows, returns on invested capital, and rate of growth. Because approximately 89% of Market Resources’ proved reserves at December 31, 2007, were natural gas, the Company’s revenues, margins, cash flow, net income and return on invested capitals are substantially more sensitive to changes in natural gas prices than to changes in oil prices.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

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;

•

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

•

conservation efforts;

•

the price, availability and acceptance of alternative fuels;

•

U.S. storage levels of natural gas, oil, and NGL;

•

differing Btu content of gas produced and quality of 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 remedial costs. Actual results most likely will vary from the estimates. Any significant variance could reduce the estimated future net revenues from proved reserves and the present value of those reserves.

Investors should not assume that the “standardized measure of discounted future net cash flows” from Questar E&P’s proved reserves referred to in this Annual Report is the current market value of the estimated natural gas and oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from Questar E&P’s proved reserves is based on prices and costs in effect on the date of the estimate, holding the prices constant throughout the life of the properties. 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 then current prices and costs may be significantly less than 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 oil and natural gas prices, causing periodic shortages. There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased costs for drilling rigs, crews and associated supplies, equipment and services. These shortages or cost increases could impact profit margin, cash flow and operating results or restrict the ability to drill wells and conduct operations.

Gas and oil 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

QUESTAR MARKET RESOURCES 2007 FORM 10-K

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, processing, transportation and distribution operations that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites could increase the level of damages resulting from these risks. Certain segments of the Company’s pipelines run through such areas. In spite of the Company’s precautions, an event could cause considerable harm to people or property, and could have a material adverse effect on the financial position and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to the Company’s customers. Such circumstances could adversely impact the Company’s ability to meet contractual obligations and retain customers.

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

Market Resources is dependent on bank credit facilities and continued access to capital markets to successfully execute its operating strategies .Market Resources also relies on access to short-term commercial paper markets. The Company is dependent on these capital sources 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. All of Market Resources’ bank loans are floating-rate debt. From time to time the Company may use interest-rate derivatives to fix the rate on a portion of its variable-rate debt. The interest rates on bank loans are tied to debt credit ratings of Market Resources and its subsidiaries published by Standard & Poor’s and Moody’s. A downgrade of credit ratings could increase the interest cost of debt and decrease future availability of money from banks and other sources. Management believes it is important to maintain investment grade credit ratings to conduct the Company’s businesses, but may not be able to keep investment grade ratings.

Risks Related to Strategy

There is no promise of continuing relationships with Questar. Market Resources is a wholly owned subsidiary of Questar and its goals and strategies are important to Questar. Questar, however, offers no explicit promise of continued ownership or of the availability of capital going forward. The Company’s ability to receive future equity and debt capital from its parent also depends on Questar’s ability to access capital markets on reasonable terms. Market Resources subsidiaries benefit from business transactions with affiliated companies. Gas Management and Wexpro have long-term agreements to gather and develop reserves for affiliate Questar Gas. All transactions are on a competitive market basis or under contracts approved by regulatory agencies and the courts, but such business relationships may not continue in the future.

A significant portion of Market Resources production, revenue and cash flow is derived from assets that are concentrated in a Rocky Mountain region. While geographic concentration of assets provides scope and scale that can reduce operating costs and provide other operating synergies, asset concentration does increase exposure to certain risks. Market Resources has extensive operations on the Pinedale Anticline and in the Greater Green River Basin of southwestern Wyoming and in the Uinta Basin of eastern Utah. Any circumstance or event that negatively impacts the operations of Questar E&P, Wexpro or Gas Management in that area could materially reduce earnings and cash flow.

Market Resources uses derivative arrangements to manage exposure to uncertain prices. Market Resources uses commodity-price derivative arrangements 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.

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. A downgrade in the Company’s credit ratings to sub-investment grade could result in the acceleration of obligations to hedge counterparties.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

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 that 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 regulations governing activities on federal and state lands in the Rocky Mountain region, notably the National Environmental Policy Act, the Endangered Species Act, the Clean Air Act, the Clean Water Act and the National Historic Preservation Act. 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 Rockies 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.

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.

Market Resources may be exposed to certain regulatory and financial risks related to climate change. Many scientists believe that carbon dioxide emissions related to the use of fossil fuels may be causing changes in the earth’s climate. 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 numerous 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. 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.

Other Risks

General economic and other conditions impact Market Resources’ results. Market Resources’ results may also be negatively affected by: changes in general 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

QUESTAR MARKET RESOURCES 2007 FORM 10-K

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

The following table sets forth Questar E&P’s estimated proved reserves as of December 31, 2007. The estimate was collectively prepared by Ryder Scott Company, H. J. Gruy and Associates, Inc. and Netherland, Sewell & Associates, Inc., independent reservoir-engineering consultants. Questar E&P does not have any long-term supply contracts with foreign governments or reserves of equity investees or of subsidiaries with a significant minority interest. At December 31, 2007, approximately 91% of Questar E&P’s estimated proved reserves were Company operated. All reported reserves are located in the United States.


Estimated proved reserves
Natural gas (Bcf)	1,668.5
Oil and NGL (MMbbl)	33.2
Total proved reserves (Bcfe)	1,867.6
Proved developed reserves (Bcfe)	1,147.4

Questar E&P’s reserve statistics for the years ended December 31, 2005 through 2007, are summarized below:


Year	Year End Reserves (Bcfe)	Proved Gas and Oil Reserves Annual Production (Bcfe)	Reserve Life (Years)
2005	1,480.4	114.2	13.0
2006	1,631.4	129.6	12.6
2007	1,867.6	140.2	13.3

In 2007, gas and oil reserves increased 14% to 1,867.6 Bcfe versus a 10% increase in 2006 to 1,631.4 Bcfe.

Questar E&P proved reserves by major operating areas at December 31, 2007 and 2006 follow:


	2007		2006
	(Bcfe)	(% of total)	(Bcfe)	(% of total)
Pinedale Anticline	1,033.9	55%	931.9	57%
Uinta Basin	301.2	16%	248.3	15%
Rockies Legacy	158.6	9%	142.3	9%
Rocky Mountains Total	1,493.7	80%	1,322.5	81%
Midcontinent	373.9	20%	308.9	19%
Questar E&P Total	1,867.6	100%	1,631.4	100%

Reserves – Cost-of-Service

The following table sets forth estimated cost-of-service proved natural gas reserves, which Wexpro develops and produces for Questar Gas under the terms of the Wexpro Agreement; and Wexpro proved oil reserves. The estimates of cost-of-service proved reserves were made by Wexpro reservoir engineers as of December 31, 2007. All reported reserves are located in the United States.

QUESTAR MARKET RESOURCES 2007 FORM 10-K


Estimated cost-of-service proved reserves
Natural gas (Bcf)	615.9
Oil (MMbbl)	4.3
Total proved reserves (Bcfe)	641.9
Proved developed reserves (Bcfe)	456.9

The gas reserves operated by Wexpro are delivered to Questar Gas at cost of service. Income from oil properties remaining after recovery of expenses and Wexpro contractual return on investment under the Wexpro Agreement is divided between Wexpro and Questar Gas. Therefore, SEC guidelines with respect to standard economic assumptions are not applicable. The SEC anticipated such potential difficulty and provides that companies may give appropriate recognition to differences arising because of the effect of the ratemaking process. 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 15 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.

In addition, to this filing, Questar E&P and Wexpro will each file estimated reserves estimates as of December 31, 2007, 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 lifting cost per Mcfe for the years ended December 31, 2007, 2006 and 2005. Lifting costs include labor, repairs, maintenance, materials, supplies and workovers, administrative costs of production offices, insurance and property and severance taxes.


	Year Ended December 31,
	2007	2006	2005
*Questar E&P*
Volumes produced and sold
Natural gas (Bcf)	121.9	113.9	100.0
Oil and NGL (MMbbl)	3.0	2.6	2.4
Total production (Bcfe)	140.2	129.6	114.2
Average realized price (including hedges)
Natural gas (Bcf)	$6.46	$6.00	$5.18
Oil and NGL (MMbbl)	53.99	49.12	41.54
Lifting costs (per Mcfe)
Lease operating expense	$ 0.63	$ 0.57	$ 0.54
Production taxes	0.43	0.45	0.60
Total lifting costs	$ 1.06	$ 1.02	$ 1.14
*Cost-of-Service*
Volumes produced
Natural gas (Bcf)	34.9	38.8	40.0
Oil and NGL (MMbbl)	0.4	0.4	0.4

Productive Wells

The following table summarizes the Company’s productive wells (including cost-of-service wells) as of December 31, 2007. All of these wells are located in the United States.

QUESTAR MARKET RESOURCES 2007 FORM 10-K


	Gas	Oil	Total
Gross	5,050	1,011	6,061
Net	2,269	482	2,751

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 2007, there were 140 gross wells with multiple completions.

The Company also holds numerous overriding-royalty interests in gas and oil wells, a portion of which is 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, 2007. “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 U.S.


	Developed⁽¹⁾		Undeveloped⁽²⁾		Total
	Gross	Net	Gross	Net	Gross	Net
	(in acres)
Arizona			480	450	480	450
Arkansas	32,721	10,362	3,111	2,207	35,832	12,569
California	314	26	1,003	168	1,317	194
Colorado	149,853	102,945	167,337	79,421	317,190	182,366
Idaho			44,175	10,643	44,175	10,643
Illinois	311	132	14,207	3,949	14,518	4,081
Indiana			1,621	467	1,621	467
Kansas	29,822	12,922	16,880	3,843	46,702	16,765
Kentucky			17,323	6,669	17,323	6,669
Louisiana	15,266	13,043	4,491	4,189	19,757	17,232
Michigan	89	8	6,240	1,262	6,329	1,270
Minnesota			313	104	313	104
Mississippi	2,904	1,799	965	398	3,869	2,197
Montana	20,149	8,138	306,139	52,852	326,288	60,990
Nevada	320	280	680	543	1,000	823
New Mexico	98,750	73,163	32,939	12,618	131,689	85,781
North Dakota	4,741	543	146,680	21,774	151,421	22,317
Ohio			202	43	202	43
Oklahoma	1,554,755	280,627	142,701	87,830	1,697,456	368,457
Oregon			43,869	7,671	43,869	7,671
South Dakota			204,398	107,829	204,398	107,829
Texas	151,497	61,773	73,219	56,520	224,716	118,293
Utah	125,265	96,509	237,281	134,772	362,546	231,281
Washington			26,631	10,149	26,631	10,149
West Virginia	969	115			969	115

QUESTAR MARKET RESOURCES 2007 FORM 10-K


Wyoming	258,441	170,891	343,421	232,325	601,862	403,216
Total	2,446,167	833,276	1,836,306	838,696	4,282,473	1,671,972

⁽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. In that event, the leases held by production will 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	Acres Expiring
	Gross	Net
12 months ending December 31,	(in acres)
2008	82,670	55,138
2009	73,608	47,129
2010	70,067	37,448
2011	31,612	26,682
2012 and later	187,438	174,229

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
	2007	2006	2005	2007	2006	2005
Net Wells Completed
Exploratory	0.3	0.9	6.1	0.4	5.2	1.5
Development	199.6	185.6	165.2	2.5	4.6	7.4

Gross Wells Completed
Exploratory	2	2	9	1	11	4
Development	426	408	370	11	18	15

Midstream Field Services – Questar Gas Management

Gas Management owns 1,550 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 Gas Transmission Co.’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 229 miles of gathering lines and associated field equipment, Uintah Basin Field Services owns 73 miles of gathering lines and associated field equipment and Three Rivers owns 40 miles of gathering lines. Gas Management owns processing plants that have an aggregate capacity of 474 MMcf of unprocessed natural gas per day.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

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. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. 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.

Grynberg Case

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

Environmental Claims

In 2004, the Environmental Protection Agency (EPA) issued two separate compliance orders alleging that Gas Management did not comply with regulatory requirements adopted to implement the federal Clean Air Act. Both orders involved facilities in the Uinta Basin of eastern Utah that were purchased by Questar E&P in mid-2001. The EPA contends such facilities are located within “Indian Country” and are subject to Federal Clean Air Act requirements, rather than air quality rules adopted by the state of Utah. Generally, EPA contends that Gas Management failed to obtain necessary pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations, in violation of federal requirements. Gas Management has generally contested EPA’s allegations, and believes that the permitting and regulatory requirements at issue can be legally avoided under Utah law. EPA has broadened its allegations to include additional potential ongoing violations of the Clean Air Act for the referenced facilities. Other Gas Management facilities in the Uinta Basin have been added to the civil penalty discussions with the EPA, with similar allegations of Clean Air Act violations. These potential violations will likely result in civil penalties of an unknown and undetermined amount in excess of $100,000. The parties are engaged in settlement discussions and have signed a tolling agreement to extend the statute of limitations for filing any claims.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

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

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.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

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 OPERATION.

SUMMARY

Market Resources net income increased 18% in 2007 compared to 2006 and 38% in 2006 over 2005. Primary due to higher realized natural gas, crude oil and NGL prices, increased gas-gathering volumes driven by an increase in third-party volumes at Gas Management and an increased investment base at Wexpro.

Following is a comparison of net income by lines of business:


	Year Ended December 31,			Change	Change
	2007	2006	2005	2007 vs. 2006	2006 vs. 2005
	(in millions, except per-share amounts)
Exploration and Production
Questar E&P	$285.5	$253.9	$172.8	$31.6	$ 81.1
Wexpro	59.2	50.0	43.7	9.2	6.3
Midstream Field Services – Gas Management	55.3	42.6	35.7	12.7	6.9
Energy Marketing – Energy Trading and other	20.8	9.6	6.0	11.2	3.6
Net income	$420.8	$356.1	$258.2	$64.7	$97.9

RESULTS OF OPERATIONS

Exploration and Production

Questar E&P

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


	Year Ended December 31,
	2007	2006	2005
	(in millions)
Operating Income
Revenues
Natural gas sales	$ 788.2	$ 684.0	$ 517.6
Oil and NGL sales	164.2	128.6	98.6
Other	3.6	3.1	4.4
Total revenues	956.0	815.7	620.6
Operating expenses
Operating and maintenance	87.9	73.6	61.8
General and administrative	56.3	42.4	33.9
Production and other taxes	60.1	58.3	68.7
Depreciation, depletion and amortization	243.5	185.7	134.7
Exploration	22.0	34.4	11.1
Abandonment and impairment	10.8	7.6	7.7

QUESTAR MARKET RESOURCES 2007 FORM 10-K


Natural gas purchases	2.2	2.8	4.2
Total operating expenses	482.8	404.8	322.1
et gain (loss) from asset sales	(0.6)	24.3	1.1
Operating income	$ 472.6	$ 435.2	$ 299.6

Operating Statistics
Questar E&P production volumes
Natural gas (Bcf)	121.9	113.9	100.0
Oil and NGL (MMbbl)	3.0	2.6	2.4
Total production (Bcfe)	140.2	129.6	114.2
Average daily production (MMcfe)	384.1	355.2	312.9
Questar E&P average realized price, net to the well (including hedges)
Natural gas (per Mcf)	$6.46	$6.00	$5.18
Oil and NGL (per bbl)	$53.99	$49.12	$41.54

Questar E&P reported net income of $285.5 million in 2007, up 12% from $253.9 million in 2006 and $172.8 million in 2005. The impact of higher realized prices for natural gas, crude oil, and NGL was partially offset by a higher average production cost structure.

Questar E&P production volumes were 140.2 Bcfe in 2007, compared to 129.6 Bcfe in the year-earlier period. On an energy-equivalent basis, natural gas comprised approximately 87% of Questar E&P 2007 production. A comparison of natural gas-equivalent production by major operating area is shown in the following table:


	Year Ended December 31,			Change	Change
	2007	2006	2005	2007 vs. 2006	2006 vs. 2005
	(in Bcfe)
Pinedale Anticline	47.4	39.5	33.2	7.9	6.3
Uinta Basin	25.4	25.1	25.6	0.3	(0.5)
Rockies Legacy	16.4	18.3	16.7	(1.9)	1.6
Rocky Mountain total^(a)	89.2	82.9	75.5	6.3	7.4
Midcontinent	51.0	46.7	38.7	4.3	8.0
Total Questar E&P	140.2	129.6	114.2	10.6	15.4

^(a)Questar E&P shut in approximately 10.3 Bcfe (net) of production in 2007 and 1.2 Bcfe (net) of production in 2006 in the Rocky Mountain region in response to low natural gas prices.

Questar E&P production from the Pinedale Anticline in western Wyoming grew 20% to 47.4 Bcfe in 2007 as a result of ongoing development drilling. Pinedale production growth is influenced by seasonal access restrictions imposed by the Bureau of Land Management that limit the company’s ability to drill and complete wells during the mid-November to early-May period.

Questar E&P Rockies Legacy properties include all of the company’s Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin. Rockies Legacy 2007 production of 16.4 Bcfe was 1.9 Bcfe lower than a year ago.

In the Midcontinent, Questar E&P grew production 9% to 51.0 Bcfe in 2007, driven by ongoing infill-development drilling in Elm Grove field in northwestern Louisiana. Net production from Elm Grove field increased to 16.4 Bcfe in 2007 compared to 14.3 Bcfe in the year-earlier period.

Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. The weighted-average realized natural gas price for Questar E&P (including the impact of hedging) was $6.46 per Mcf compared to $6.00 per Mcf for the same period in

QUESTAR MARKET RESOURCES 2007 FORM 10-K

2006, an 8% increase. Realized oil and NGL prices in 2007 averaged $53.99 per bbl, compared with $49.12 per bbl during the prior-year period, a 10% increase. A regional comparison of average realized prices, including hedges, is shown in the following table:


	Year Ended December 31,			Change	Change
	2007	2006	2005	2007 vs. 2006	2006 vs. 2005
Natural gas (per Mcf)
Rocky Mountains	$5.92	$5.73	$5.01	$0.19	$0.72
Midcontinent	7.42	6.47	5.49	0.95	0.98
Volume-weighted average	6.46	6.00	5.18	0.46	0.82
Oil and NGL (per bbl)
Rocky Mountains	$53.51	$46.62	$42.08	$6.89	$4.54
Midcontinent	54.85	54.93	40.25	(0.08)	14.68
Volume-weighted average	53.99	49.12	41.54	4.87	7.58

Questar E&P hedged or pre-sold approximately 75% of gas production in 2007, and hedged or pre-sold 70% of gas production in the comparable 2006 period. Hedging increased Questar E&P gas revenues by $245.7 million in 2007 and $53.7 million in 2006. The company hedged or pre-sold approximately 61% of its oil production in 2007, and hedged or pre-sold 78% of its oil production in the same period of 2006. Oil hedges reduced revenues $17.2 million in 2007 and $19.6 million in 2006.

Questar may hedge up to 100% of forecasted production from proved reserves to lock in acceptable returns on invested capital and to protect returns, cash flow and net income from a decline in commodity prices. During 2007, Questar E&P hedged additional production through 2010. In the second quarter of 2006, the company began using basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials that may result from capacity constraints on regional gas pipelines. Net mark-to-market changes in natural gas basis-only swaps increased 2007 net income by $3.6 million compared to a $1.2 million reduction in the prior-year period. Derivative positions as of December 31, 2007, are summarized in Item 7A of Part II in this annual report.

Questar E&P production costs (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense, allocated-interest expense and production taxes) per Mcfe of production increased 13% to $3.38 per Mcfe in 2007 compared to $2.99 per Mcfe in 2006. Questar E&P production costs are summarized in the following table:


	Year Ended December 31,			Change	Change
	2007	2006	2005	2007 vs. 2006	2006 vs. 2005
	(per Mcfe)
Depreciation, depletion and amortization	$1.74	$1.43	$1.18	$0.31	$0.25
Lease operating expense	0.63	0.57	0.54	0.06	0.03
General and administrative expense	0.40	0.33	0.30	0.07	0.03
Allocated-interest expense	0.18	0.21	0.21	(0.03)
Production taxes	0.43	0.45	0.60	(0.02)	(0.15)
Total production costs	$3.38	$2.99	$2.83	$0.39	$0.16

Production volume-weighted average depreciation, depletion and amortization expense per Mcfe increased in 2007 due to higher costs for drilling, completion and related services, higher cost of steel casing, other tubulars and wellhead equipment, the ongoing depletion of older, lower-cost reserves and the increasing component of Questar E&P production derived from higher-cost fields such as Elm Grove in the Midcontinent and Vermillion Basin in the Rockies. Lease operating expense per Mcfe increased due to higher costs of materials and consumables, increased produced-water disposal costs and higher well-workover activity. General and administrative expense per Mcfe grew due to increased labor and legal expenses in 2007. Allocated-interest expense per unit of production decreased in 2007 due to reduced debt expense and increased 2007 production. Production taxes were lower in 2007 due to lower market prices for natural gas. The company pays production taxes per Mcfe based on sales prices before the impact of hedges.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Questar E&P exploration expense decreased $12.4 million or 36% in 2007 compared to 2006. In 2006, Questar E&P recorded a $10.0 million charge related to the abandoned deep exploratory portion of the Stewart Point 15-29 well on the Pinedale Anticline after failing to establish commercial production in the Hilliard and Rock Springs formations.

In 2006, Questar E&P sold certain proved reserves and undeveloped leasehold interests in western Colorado and recognized a pre-tax gain of $22.7 million.

Questar E&P major operating areas are discussed below.

Pinedale Anticline: As of December 31, 2007, Market Resources (including both Questar E&P and Wexpro) operated and had working interests in 250 producing wells on the Pinedale Anticline compared to 195 a year earlier. Of the 250 producing wells, Questar E&P has working interests in 228 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 71 of the 250 producing wells.

In 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10-acre-density drilling for Lance Pool wells on about 12,700 (gross) acres of Market Resources 18,208 acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the currently estimated productive limits of Market Resources core acreage in the field. At December 31, 2007, Questar E&P had booked 355 proved undeveloped locations on a combination of 10- and 20-acre density and reported estimated net proved reserves at Pinedale of 1,033.9 Bcfe, or 55% of Questar E&P’s total proved reserves. The company is evaluating the economic potential of development on five-acre density at Pinedale. In January 2008, the WOGCC approved five-acre-density drilling for Lance Pool wells on about 4,200 gross acres of Market Resources Pinedale leasehold. If five-acre-density development is appropriate for a majority of its leasehold, the company currently estimates up to an additional 1,600 wells will be required to fully develop the Lance Pool on its acreage.

Uinta Basin: As of December 31, 2007, Questar E&P had a working interest in 857 producing wells in the Uinta Basin of eastern Utah, compared to 811 at December 31, 2006. At December 31, 2007, Questar E&P had booked 123 proved-undeveloped locations and reported estimated net proved reserves in the Uinta Basin of 301.2 Bcfe or 16% of Questar E&P’s total proved reserves. Uinta Basin proved reserves are found in a series of vertically-stacked, laterally discontinuous reservoirs at depths of 5,000 feet to deeper than 16,000 feet. Questar E&P owns interests in over 242,000 gross leasehold acres in the Uinta Basin.

Rockies Legacy: The remainder of Questar E&P Rocky Mountain region leasehold interests, productive wells and proved reserves are distributed over a number of basins, 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 158.6 Bcfe or 9% of Questar E&P total proved reserves at December 31, 2007. Within the division, exploratory and development activity is planned for 2008 within the San Juan, Paradox, Powder River, Green River and Vermillion basins.

In the Vermillion Basin on the southwestern Wyoming-northwestern Colorado state line, Market Resources companies continue to evaluate the potential of several formations under 146,000 net leasehold acres. As of December 31, 2007, Market Resources had recompleted two older wells and drilled and completed 20 new wells. The targets are the Baxter Shale, a thick, overpressured shale found at depths of about 9,500 to about 13,000 feet and deeper Frontier and Dakota tight-sand formations at depths to about 14,000 feet.

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 Louisiana, Texas and Arkansas. With the exception of the Elm Grove field in northwest Louisiana and the Granite Wash play in the Texas Panhandle, Questar E&P Midcontinent leasehold interests are highly fragmented, with no significant concentration of property interests. Questar E&P reported Midcontinent proved reserves of 373.9 Bcfe on December 31, 2007, 20% of Questar E&P’s total year-end proved reserves at December 31, 2007.

Questar E&P continues a two-rig infill-development project on its largest single Midcontinent asset, the Elm Grove field in northwest Louisiana. As of December 31, 2007, Questar E&P operated or had working interests in 293 producing wells in the Elm Grove field compared to 231 at December 31, 2006. At December 31, 2007, Questar E&P had 38 proved-undeveloped locations and reported estimated net proved reserves at Elm Grove of 104.6 Bcfe, or 6% of the company’s total proved reserves.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Wexpro

Wexpro reported net income of $59.2 million in 2007 compared to $50.0 million in 2006, an 18% increase. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19% to 20% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation (investment base). Wexpro investment base at December 31, 2007, was $300.4 million, an increase of $39.8 million or 15% from December 31, 2006. Wexpro produced 34.9 Bcf of cost-of-service gas in 2007.

Midstream Field Services – Questar Gas Management

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


	Year Ended December 31,
	2007	2006	2005
	(in millions)
Operating Income
Revenues
Gathering	$111.4	$ 89.2	$74.5
Processing	94.9	94.7	80.7
Total revenues	206.3	183.9	155.2
Operating expenses
Operating and maintenance	83.6	92.4	85.2
General and administrative	17.2	12.2	7.5
Production and other taxes	1.4	0.6	0.7
Depreciation, depletion and amortization	19.1	15.3	11.3
Abandonment and impairments	0.4
Total operating expenses	121.7	120.5	104.7
Net gain from asset sales		1.0
Operating income	$ 84.6	$ 64.4	$ 50.5

Operating Statistics
Natural gas processing volumes
NGL sales (MMgal)	76.5	88.1	88.4
NGL sales price (per gal)	$0.98	$0.88	$0.77
Fee-based processing volumes (in millions of MMBtu)
For unaffiliated customers	44.1	37.5	13.2
For affiliated customers	82.5	82.9	62.3
Total fee-based processing volumes	126.6	120.4	75.5
Fee-based processing (per MMBtu)	$0.15	$0.14	$0.15
Natural gas gathering volumes (in millions of MMBtu)
For unaffiliated customers	162.1	124.1	112.6
For affiliated customers	128.1	150.0	144.4
Total gas gathering volumes	290.2	274.1	257.0
Gas gathering revenue (per MMBtu)	$0.32	$0.29	$0.25

Gas Management grew net income to $55.3 million in 2007 compared to $42.6 million in the 2006 period, a 30% increase driven by higher gathering and processing volumes.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Gathering volumes increased 16.1 million MMBtu, or 6% to 290.2 million MMBtu in 2007. New projects serving third parties in the Uinta Basin and expanded Pinedale production contributed to a 31% increase in third-party volumes during 2007. Total gathering margins (revenues minus direct expenses) during 2007 increased 35% to $67.1 million compared to $49.6 million in 2006.

Fee-based gas-processing volumes were 126.6 million MMBtu in 2007, a 5% increase compared to the 2006 period. Fee-based gas-processing revenues increased 14% or $2.2 million, while gross margin from keep-whole processing increased 40% or $12.9 million in 2007. Approximately 74% of Gas Management net operating revenue (total revenue less processing plant-shrink) is derived from fee-based contracts, compared to 77% in 2006. Gas Management uses forward sales contracts to reduce margin volatility associated with keep-whole contracts. Forward sales contracts reduced NGL revenues by $5.8 million in 2007 and increased revenues by $0.7 million in 2006.

Energy Marketing – Questar Energy Trading

Energy Trading grew net income 117% to $20.8 million in 2007 compared to $9.6 million in 2006, driven primarily by increased trading margins. Gross marketing margin (gross revenues less costs for gas and oil purchases, transportation and gas storage) totaled $31.6 million in 2007 compared to $16.0 million a year ago. The increase in trading margin was due primarily to increased storage activity over the same period last year. Energy Trading reported unaffiliated revenues of $504.4 million in 2007 compared with $656.0 million in 2006, a 23% decrease primarily resulting from lower regional-market prices for natural gas. The weighted-average natural gas sales price decreased 20% in 2007 to $4.29 per MMBtu, compared to $5.34 per MMBtu for the 2006 period.

Consolidated Results Before Net Income

Net gain (loss) from asset sales

During 2006, Questar E&P sold certain proved reserves and undeveloped leasehold interests in western Colorado and recognized a pre-tax gain of $22.7 million. The gain is included in the Consolidated Statement of Income line item “Net gain (loss) from asset sales”.

Income from unconsolidated affiliates

Income from unconsolidated affiliates, primarily Rendezvous Gas Services, was $8.9 million in 2007 compared to $7.5 million in 2006. Rendezvous Gas Services provides gas-gathering services for the Pinedale and Jonah producing areas. Rendezvous gathering volumes increased 20% in 2007 compared to 2006 and 1% in 2006 compared to 2005.

Interest expense and loss on early extinguishment of debt

Interest expense was 5% higher in 2007 compared to 2006 as a result of higher interest rates and increased borrowings. Interest expense rose in 2006 compared to 2005 due primarily to increased average debt levels and higher interest rates on short term debt outstanding in the early part of 2006. Market Resources recognized a $1.7 million pre-tax loss in 2006 on the early extinguishment of its 7% Notes due 2007.

Net mark-to-market gain (loss) on basis-only swaps

The Company uses basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials that may result from capacity constraints on regional gas pipelines. The Company recognized a net mark-to-market gain of $5.7 million on the natural gas basis-only swaps in 2007 compared with a net mark-to-market loss of $1.9 million in 2006.

Investing Activities

Capital spending in 2007 amounted $943.9 million. The details of capital expenditures in 2007 and 2006 and a forecast for 2008 are shown in the table below:


	Year Ended December 31,
	2008 Forecast	2007	2006
	(in millions)
Drilling and other exploration	$ 76.7	$ 32.7	$ 13.6
Dry exploratory well expenses		12.3	26.3
Development drilling	779.4	612.0	532.6
Wexpro development drilling	125.7	97.2	76.8

QUESTAR MARKET RESOURCES 2007 FORM 10-K


Reserve acquisitions	643.9	44.8	29.3
Production	18.7	28.2	22.7
Midstream field services	389.1	125.7	80.4
Storage	0.2	0.3	1.1
General	7.8	11.1	5.6
Capital expenditure accruals		(20.4)	(35.7)
Total	$2,041.5	$943.9	$752.7

In 2007 and 2006, Market Resources increased drilling activity at Pinedale and in the Midcontinent region. During 2007, Market Resources participated in 607 wells (202.8 net), resulting in 199.9 net successful gas and oil wells and 2.9 net dry or abandoned wells. The 2007 net drilling-success rate was 98.6%. There were 167 gross wells in progress at year-end. Market Resources also increased investment in its midstream gathering and processing-services business to expand capacity in both western Wyoming and eastern Utah in response to growing equity and third-party production volumes. On January 31, 2008, Questar E&P entered into agreements with multiple private sellers to acquire two significant natural gas development properties in northwest Louisiana for an aggregate purchase price of $655 million. In February 2008, Market Resources established a $700 million term-loan credit facility to finance the purchase of the Louisiana natural gas development properties. Market Resources plans to expand its current revolving credit facility to $800 million and issue up to $500 million of additional long-term debt to retire the $700 million term loan credit facility.

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, 2007:


	Payments Due by Year
	Total	2008	2009	2010	2011	2012	After 2012
	(in millions)
Long-term debt	$500.0				$150.0	$100.0	$250.0
Interest on fixed-rate long-term debt	166.7	$26.4	$26.4	$26.4	17.0	15.1	55.4
Transportation contracts	55.5	8.7	7.9	7.6	7.3	5.3	18.7
Operating leases	16.4	3.6	3.6	3.3	2.8	1.8	1.3
Total	$738.6	$38.7	$37.9	$37.3	$177.1	$122.2	$325.4

The Company had $100 million of variable-rate long-term debt outstanding due 2012 with an interest rate of 5.55% at December 31, 2007.

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. For 2007, revisions of reserve estimates, other than revisions related to Pinedale increased-density, resulted in a 46.2 Bcfe increase in Questar E&P’s proved reserves and a 30.0 Bcfe decrease in cost-of-service proved reserves. Revisions associated with Pinedale increased-density drilling added 126.8 Bcfe to Questar E&P’s estimated proved reserves at December 31, 2007, and 25.9 Bcfe of additional cost-of-service proved reserves. See Note 15 for more information on the Company’s estimated proved reserves.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Successful Efforts Accounting for Gas and Oil Operations

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

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

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

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

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

Accounting for Derivatives Contracts

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

Revenue Recognition

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

Recent Accounting Developments

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

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

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

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Commodity-Price Risk Management

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

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

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

Market Resources enters into commodity-price derivative arrangements that do not require collateral deposits. Counterparties include banks and energy-trading firms with investment-grade credit ratings. The amount of credit available may vary depending on the credit ratings assigned to Market Resources debt. In addition to the counterparty arrangements, Market Resources has a $182.0 million long-term revolving-credit facility with banks with $100 million borrowed at December 31, 2007.

Generally, derivative instruments are matched to equity gas and oil production, thus qualifying as cash-flow hedges under the accounting provisions of SFAS 133 as amended and interpreted. Changes in the fair value of cash-flow hedges are recorded on the balance sheet and in accumulated other comprehensive income (loss) until the underlying gas or oil is produced. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. The ineffective portion of cash-flow hedges is immediately recognized in the determination of net income.

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

A summary of Market Resources derivative positions for equity production as of December 31, 2007, is shown below:


	Rocky			Rocky
Time Periods	Mountains	Midcontinent	Total	Mountains	Midcontinent	Total
				Estimated
	Gas (Bcf) Fixed-price Swaps			Average price per Mcf, net to the well
2008
First half	33.0	17.3	50.3	$6.95	$7.93	$7.29
Second half	33.4	17.4	50.8	6.97	7.93	7.30
12 months	66.4	34.7	101.1	6.96	7.93	7.30

QUESTAR MARKET RESOURCES 2007 FORM 10-K


2009
First half	23.5	12.0	35.5	$7.02	$7.66	$7.24
Second half	23.9	12.2	36.1	7.02	7.66	7.24
12 months	47.4	24.2	71.6	7.02	7.66	7.24

2010
First half	3.3	6.9	10.2	$6.95	$7.58	$7.37
Second half	3.4	6.9	10.3	6.95	7.58	7.37
12 months	6.7	13.8	20.5	6.95	7.58	7.37

				Estimated
	Gas (Bcf) Basis-only Swaps			Average basis per Mcf, net to the well
2008
First half	5.1		5.1	$1.65		$1.65
Second half	5.1		5.1	1.65		1.65
12 months	10.2		10.2	1.65		1.65

2009
First half	11.8	1.7	13.5	$1.21	$1.08	$1.19
Second half	12.0	1.7	13.7	1.21	1.08	1.19
12 months	23.8	3.4	27.2	1.21	1.08	1.19

2010
First half		1.7	1.7		$0.94	$0.94
Second half		1.7	1.7		0.94	0.94
12 months		3.4	3.4		0.94	0.94

				Estimated
	Oil (Mbbl) Fixed-price Swaps			Average price per bbl, net to the well
2008
First half	419	218	637	$67.39	$70.77	$68.55
Second half	423	221	644	67.39	70.77	68.55
12 months	842	439	1,281	67.39	70.77	68.55

2009
First half	217	145	362	$60.55	$66.55	$62.95
Second half	221	147	368	60.55	66.55	62.95
12 months	438	292	730	60.55	66.55	62.95

As of December 31, 2007, Market Resources held commodity-price hedging contracts covering about 245.0 million MMBtu of natural gas, 2.0 million barrels of oil, 5.0 million gallons of NGL and basis-only swaps on an additional 40.8 Bcf of natural gas. A

QUESTAR MARKET RESOURCES 2007 FORM 10-K

year earlier Market Resources hedging contracts covered 204.2 million MMBtu of natural gas, 1.8 million barrels of oil, 22.7 million gallons of NGL and natural gas basis-only swaps on an additional 47.7 Bcf.

The following table summarizes changes in the fair value of derivative contracts from December 31, 2006 to December 31, 2007:


	Fixed-Price Swaps	Basis-Only Swaps	Total
	(in millions)
Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2006	$205.6	($ 1.9)		$203.7
Contracts realized or otherwise settled	(153.9)	(1.2)	(155.1)
Change in gas and oil prices on futures markets	(112.4)	(30.4)	(142.8)
Contracts added	111.8	36.9	148.7
Contracts redesignated as fixed-price swaps	(0.4)	0.4
Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2007	$ 50.7	$ 3.8		$ 54.5

A table of the net fair value of gas- and oil-derivative contracts as of December 31, 2007, is shown below. About $68.8 million of the fair value of all contracts will settle in the next 12 months and the fair value of cash-flow hedges will be reclassified from other comprehensive income:


	Fixed-Price Swaps	Basis-Only Swaps			Total
	(in millions)
Contracts maturing by December 31, 2008	$70.2	($ 1.4)			$68.8
Contracts maturing between January 1, 2009 and December 31, 2009	(13.7)	5.3			(8.4)
Contracts maturing between January 1, 2010 and December 31, 2010	(5.8)	(0.1)			(5.9)
Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2007	$50.7		$ 3.8	$54.5

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


	At December 31,
	2007	2006
	(in millions)
Net fair value – asset (liability)	$ 54.5	$203.7
Value if market prices of gas and oil and basis differentials decline by 10%	217.7	334.6
Value if market prices of gas and oil and basis differentials increase by 10%	(108.8)	72.8

Credit Risk

Market Resources requests credit support and, in some cases, prepayment from companies with unacceptable credit risks. Market Resources five largest customers are Sempra Energy Trading Corp., Enterprise Products Operating, Chevron USA Inc., Nevada Power Company, and Occidental Energy Marketing Inc. Sales to these companies accounted for 19% of Market Resources revenues before elimination of intercompany transactions in 2007, and their accounts were current at December 31, 2007.

Interest-Rate Risk

The fair value of fixed-rate debt is subject to change as interest rates fluctuate. The Company had $400.0 million of fixed-rate long-term debt at December 31, 2007 and 2006 with fair values of $403.1 million at December 31, 2007 and $412.8 million at December 31, 2006. If interest rates had declined 10%, fair value would increase to $416.2 million in 2007 and $427.2 million in 2006. The fair value calculations do not represent the cost to retire the debt securities.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Financial Statements:

Page No.

Report of Independent Registered Public Accounting Firm

Consolidated Statements of Income, three years ended December 31, 2007

Consolidated Balance Sheets at December 31, 2007 and 2006

Consolidated Statements of Common Shareholder’s Equity, three years ended

December 31, 2007

Consolidated Statements of Cash Flows, three years ended December 31, 2007

Notes Accompanying Consolidated Financial Statements

Financial Statement Schedules:

For the three years ended December 31, 2007

Valuation and Qualifying Accounts

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 2007 FORM 10-K

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, 2007 and 2006, 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, 2007. 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, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the financial statements, Questar Market Resources adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes effective January 1, 2007, and Statement of Financial Accounting Standard No. 123R, Share Based Payments, effective January 1, 2006.

/s/ Ernst & Young LLP

Salt Lake City, Utah

February 22, 2008

QUESTAR MARKET RESOURCES 2007 FORM 10-K

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME


	Year Ended December 31,
	2007	2006	2005
	(in millions)
REVENUES
From unaffiliated customers	$1,671.3	$1,659.4	$1,668.7
From affiliated companies	172.1	176.4	159.5
Total Revenues	1,843.4	1,835.8	1,828.2

OPERATING EXPENSES
Cost of natural gas and other products sold (excluding operating expenses shown separately)	474.7	652.6	888.3
Operating and maintenance	187.9	180.4	158.6
General and administrative	91.3	69.2	54.6
Production and other taxes	81.6	89.4	102.2
Depreciation, depletion and amortization	295.1	235.0	173.8
Exploration	22.0	34.4	11.5
Abandonment and impairment	11.2	7.6	7.9
Wexpro Agreement-oil income sharing	4.9	5.5	6.1
Total Operating Expenses	1,168.7	1,274.1	1,403.0
Net gain (loss) from asset sales	(1.3)	25.2	0.9
OPERATING INCOME	673.4	586.9	426.1
Interest and other income	9.7	5.8	5.6
Income from unconsolidated affiliates	8.9	7.5	7.5
Net mark-to-market gain (loss) on basis-only swaps	5.7	(1.9)
Loss on early extinguishment of debt		(1.7)
Interest expense	(35.6)	(33.9)	(30.9)
INCOME BEFORE INCOME TAXES	662.1	562.7	408.3
Income taxes	241.3	206.6	150.1
NET INCOME	$ 420.8	$ 356.1	$ 258.2

See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES 2007 FORM 10-K

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS


	December 31,
	2007	2006
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents		$ 18.2
Notes receivable from Questar	$ 103.2	69.8
Federal income taxes recoverable	4.6	1.4
Accounts receivable, net	246.1	235.9
Accounts receivable from affiliates	18.3	21.8
Fair value of derivative contracts	78.1	155.5
Inventories, at lower of average cost or market
Gas and oil storage	23.2	27.7
Materials and supplies	33.2	28.7
Prepaid expenses and other	18.2	22.5
Total Current Assets	524.9	581.5
Property, Plant and Equipment – successful efforts method of accounting for gas and oil properties
Questar E&P
Proved properties	3,306.9	2,646.6
Unproved properties, not being depleted	55.6	42.7
Support equipment and facilities	23.3	18.5
Wexpro	766.1	658.6
Gas Management	516.5	404.2
Energy Trading and other	39.9	37.9
	4,708.3	3,808.5
Less accumulated depreciation, depletion and amortization
Questar E&P	1,114.3	901.5
Wexpro	331.4	305.4
Gas Management	115.3	97.3
Energy Trading and other	6.7	5.5
	1,567.7	1,309.7
Net Property, Plant and Equipment	3,140.6	2,498.8
Investment in unconsolidated affiliates	52.8	37.5
Other Assets
Goodwill	60.9	60.9
Contract receivable from Questar Gas	3.9	4.2
Fair value of derivative contracts	7.8	49.0
Other noncurrent assets	15.5	17.7
Total Other Assets	88.1	131.8
Total Assets	$3,806.4	$3,249.6

QUESTAR MARKET RESOURCES 2007 FORM 10-K

LIABILITIES AND SHAREHOLDER’S EQUITY


	December 31,
	2007	2006
	(in millions)
Current Liabilities
Notes payable to Questar	$ 118.9	$ 142.6
Accounts payable and accrued expenses
Accounts and other payables	303.7	295.3
Accounts payable to affiliates	13.0	17.3
Production and other taxes	40.9	53.4
Interest	9.3	8.8
Total accounts payable and accrued expenses	366.9	374.8
Fair value of derivative contracts	9.3	0.6
Deferred income taxes – current	13.3	41.7
Total Current Liabilities	508.4	559.7

Long-term debt	499.3	399.2
Deferred income taxes	731.4	579.0
Asset retirement obligations	145.3	128.3
Fair value of derivative contracts	22.1	0.2
Other long-term liabilities	39.8	38.4

Commitments and Contingencies – Note 8

COMMON SHAREHOLDER’S EQUITY
Common stock – par value $1 per share;
25.0 shares authorized; 4.3 shares issued and outstanding	4.3	4.3
Additional paid-in capital	130.9	122.0
Retained earnings	1,693.9	1,290.4
Accumulated other comprehensive income	31.0	128.1
Total Common Shareholder’s Equity	1,860.1	1,544.8

Total Liabilities and Common Shareholder’s Equity	$3,806.4	$3,249.6

See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES 2007 FORM 10-K

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY


				Accumulated
		Additional		Other	Comprehensive
	Common	Paid-in	Retained	Comprehensive	Income
	Stock	Capital	Earnings	Income (Loss)	(Loss)
	(in millions)
Balance at January 1, 2005	$ 4.3	$116.0	$ 710.7	($ 42.1)
2005 net income			258.2		$258.2
Dividends paid			(17.3)
Other comprehensive loss
Change in unrealized fair value of derivatives				(251.5)	(251.5)
Income taxes				95.5	95.5
Total comprehensive income					$102.2
Balance at December 31, 2005	4.3	116.0	951.6	(198.1)
2006 net income			356.1		$356.1
Dividends paid			(17.3)
Share-based compensation		6.0
Other comprehensive income
Change in unrealized fair value of derivatives				524.9	524.9
Income taxes				(198.7)	(198.7)
Total comprehensive income					$682.3
Balance at December 31, 2006	4.3	122.0	1,290.4	128.1
2007 net income			420.8		$420.8
Dividends paid			(17.3)
Share-based compensation		8.9
Other comprehensive income
Change in unrealized fair value of derivatives				(156.1)	(156.1)
Income taxes				59.0	59.0
Total comprehensive income					$323.7
Balance at December 31, 2007	$ 4.3	$130.9	$1,693.9	$ 31.0

See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES 2007 FORM 10-K

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2007	2006	2005
	(in millions)
OPERATING ACTIVITIES
Net income	$420.8	$356.1	$258.2
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	296.0	236.8	174.9
Deferred income taxes	183.0	110.7	93.2
Abandonment and impairment	11.2	7.6	7.9
Share-based compensation	8.9	6.0
Dry exploration well expenses	12.3	26.3	3.1
Net (gain) loss from asset sales	1.3	(25.2)	(0.9)
Income from unconsolidated affiliates	(8.9)	(7.5)	(7.5)
Distribution from unconsolidated affiliates	10.4	7.1	10.0
Net mark-to-market (gain) loss on basis-only swaps	(5.7)	1.9
Loss on early extinguishment of debt		1.7
Changes in operating assets and liabilities:
Accounts receivable	(6.7)	32.7	(95.3)
Inventories	5.8	0.7	(26.0)
Prepaid expenses	4.3	0.9	(6.7)
Accounts payable and accrued expenses	(34.0)	(28.0)	121.2
Federal income taxes	(3.2)	12.7	(18.7)
Other		(12.1)	7.0
NET CASH PROVIDED FROM OPERATING ACTIVITIES	895.5	728.4	520.4

INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(929.1)	(746.4)	(576.2)
Other investments	(14.8)	(6.3)
Total capital expenditures	(943.9)	(752.7)	(576.2)
Proceeds from disposition of assets	4.6	29.0	1.9
NET CASH USED IN INVESTING ACTIVITIES	(939.3)	(723.7)	(574.3)

FINANCING ACTIVITIES
Checks in excess of cash balances			(4.3)
Change in notes receivable from Questar	(33.4)	19.3	(39.7)
Change in notes payable to Questar	(23.7)	(38.2)	119.6
Long-term debt issued, net of issue costs	100.0	247.0	200.0
Long-term debt repaid		(200.0)	(200.0)
Early extinguishment of debt costs		(1.7)

QUESTAR MARKET RESOURCES 2007 FORM 10-K


Dividends paid	(17.3)	(17.3)	(17.3)
NET CASH PROVIDED FROM FINANCING ACTIVITIES	25.6	9.1	58.3
Change in cash and cash equivalents	(18.2)	13.8	4.4
Beginning cash and cash equivalents	18.2	4.4
Ending cash and cash equivalents	$	$ 18.2	$ 4.4

Supplemental Disclosure of Cash Paid During the Year for:
Interest	$34.5	$31.9	$30.4
Income taxes	64.9	81.1	73.8

See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

NOTES ACCOMPANYING CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies

Nature of Business

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

Wexpro Company (Wexpro) manages, develops and produces cost-of-service reserves for gas utility affiliate, Questar Gas;

Questar Gas Management Company (Gas Management) provides midstream field services including natural gas-gathering and processing services for affiliates and third parties; and

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

Principles of Consolidation

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

Investment in Unconsolidated Affiliates

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

The principal unconsolidated affiliates and Market Resources’ ownership percentage as of December 31, 2007, were Rendezvous Gas Services, LLC, a limited liability corporation (50%), Uintah Basin Field Services, LLC, a limited liability corporation (38%) and Three Rivers Gathering, a limited liability corporation (50%). These entities are engaged in gathering and compressing natural gas.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Use of Estimates

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

Revenue Recognition

Market Resources subsidiaries recognize revenues in the period that services are provided or products are delivered. Revenues reflect the impact of price-hedging instruments. Revenues associated with the production of gas and oil are accounted for using the sales method, whereby revenue is recognized as gas and oil is sold to purchasers. A liability is recorded to the extent that the company has sold volumes in excess of its share of remaining gas and oil reserves in an underlying property. Market Resources imbalance obligations at December 31, 2007 and 2006, were $2.7 million.

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

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 11 for more information on the Wexpro Agreement.

Regulation of Underground Storage

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

Cash and Cash Equivalents

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

Notes Receivable from Questar

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

Property, Plant and Equipment

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

Gas and oil properties

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

Capitalized costs of unproved properties are generally combined and amortized over the expected holding period for such properties. 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.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Capitalized exploratory well costs

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

Cost-of-service gas and oil operations

The successful efforts method of accounting is used for “cost-of-service” gas and oil properties owned by Questar Gas and managed and developed by Wexpro. Cost-of-service gas and oil properties are properties for which the operations and return on investment are subject to the Wexpro Agreement (see Note 11). 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. That cost includes a return on Wexpro’s investment. Oil produced from the cost-of-service properties is sold at market prices. Proceeds are credited pursuant to the terms of the agreement, allowing Questar Gas to share in the proceeds for the purpose of reducing natural gas rates.

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 for the periods:


	2007	2006	2005
Gas and oil properties, per Mcfe	$1.74	$1.43	$1.18
Cost-of-service gas and oil properties, per Mcfe	1.09	$1.04	0.83

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 an impairment of gas and oil reserves caused by mechanical problems, a faster-than-expected decline of reserves, lease-ownership issues, an 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.

Goodwill and Other Intangible Assets

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

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

The Company capitalizes interest costs when applicable. The Wexpro Agreement requires capitalization of AFUDC on cost-of-service construction projects. The FERC requires the capitalization of AFUDC during the construction period of rate-regulated

QUESTAR MARKET RESOURCES 2007 FORM 10-K

plant and equipment. AFUDC on equity funds amounted to $1.3 million in 2007, $0.9 million in 2006 and $0.4 million in 2005 and increased interest and other income in the Consolidated Statements of Income.

Derivative Instruments

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

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

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

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

When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are included in income in the same period that the underlying production or other contractual commitment is delivered. When a derivative instrument is associated with an anticipated transaction that is no longer probable, the gain or loss on the derivative is reclassified from other comprehensive income and recognized currently in the results of operations. When a derivative is terminated before its contract expires, the associated gain or loss is recognized in income over the life of the previously hedged production.

Basis-Only Swaps

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

Physical Contracts

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

Financial Contracts

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

Credit Risk

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

Bad debt expense amounted to $0.1 million in 2007, $1.4 million in 2006 and $0.1 million in 2005. The allowance for bad debt expenses was $3.3 million and $4.3 million at December 31, 2007 and 2006, respectively.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Income Taxes

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

In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). The interpretation applies to all tax positions related to income taxes subject to SFAS 109 “Accounting for Income Taxes.” FIN 48 provides guidance for the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Questar adopted the provisions of FIN 48 effective January 1, 2007. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company’s recorded income tax benefits will be fully realized. There were no unrecognized tax benefits at the beginning or at the end of the twelve-month period ended December 31, 2007. Income tax returns for 2004 and subsequent years are subject to examination. As of the date of adoption, there were no amounts accrued for penalties or interest related to unrecognized tax benefits.

Share-Based Compensation

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

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

Comprehensive Income

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

Business Segments

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

Recent Accounting Developments

SFAS 157 “Fair Value Measures”

The FASB issued SFAS 157 “Fair Value Measures” in September 2006. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measures required by other accounting rules. It does not change existing guidance as to whether or not an instrument is carried at fair value. SFAS 157 will be effective for Questar beginning January 1, 2008. The Company has reviewed the requirements of SFAS 157 and does not expect its adoption to impact financial position, results of operations or cash flows.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities”

The FASB issued SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities in February 2007.” SFAS 159 permits the measurement of certain financial instruments at fair value. Entities may choose to measure eligible items at fair value at certain election dates and report unrealized gains and losses on such items for each subsequent reporting period. SFAS 159 will be effective for Questar beginning January 1, 2008. The Company has reviewed the requirements of SFAS 159 and does not expect its adoption to impact financial position, results of operations or cash flows.

SFAS 141(R) “Business Combinations”

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

SFAS 160 “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”

SFAS 160 requires ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated balance sheets within shareholders’ equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the consolidated statements of income, changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently; and any retained noncontrolling equity investment in the former subsidiary be initially measured at fair value. SFAS 160 is effective beginning January 1, 2009. The Company is currently evaluating the impact of SFAS 160.

Reclassifications

Certain reclassifications were made to prior-year consolidated financial statements to conform with the 2007 presentation.

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

Note 2 – Share-Based Compensation

Prior to January 1, 2006, Questar and the Company accounted for share-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion (APBO) 25 “Accounting for Stock Issued to Employees” and related interpretations. No compensation cost was recorded for stock options because the exercise price equaled the market price on the date of grant. Under SFAS 123R “Share Based Payment,” the fair value of stock options was determined on the grant date using the Black-Scholes-Merton option-valuation model. The granting of restricted shares results in recognition of compensation cost under APBO 25 and SFAS 123R. Restricted shares are valued at the grant-date market price and amortized to expense over the vesting period. Market Resources uses an accelerated method in recognizing share-based compensation costs with graded-vesting periods.

Questar and the Company implemented SFAS 123R effective January 1, 2006, and chose the modified prospective phase-in method of accounting by SFAS 123R. The modified prospective phase-in method requires recognition of compensation costs for all share-based payments granted, modified or settled after January 1, 2006, as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. Adopting SFAS 123R resulted in lower income before income taxes and net income than if the Company had continued to account for share-based compensation under APBO 25 due to expensing the fair value of stock options. Income before income taxes and net income were approximately $0.7 million and 0.4 million lower, respectively, for the year ended December 31, 2007. Income before income taxes and net income for the year ended December 31, 2006, were approximately $0.7 million and $0.4 million lower, respectively. The pro forma share-based compensation expense impact for the year of 2005 was approximately $0.8 million. Amortized share-based compensation associated with unvested restricted shares amounted to $8.2 million for the year ended December 31, 2007.

There were 60,000 stock options issued to Market Resources’ LTSIP in 2007. Fair value was calculated using the Black-Scholes-Merton model on the grant date.

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

QUESTAR MARKET RESOURCES 2007 FORM 10-K


	Options Outstanding	Price Range	Weighted Average Price
Balance at January 1, 2006	1,802,638	$7.50 – $38.57	$15.09
Exercised	(364,496)	7.50 – 17.55	11.57
Balance a December 31, 2006	1,438,142	7.50 – 38.57	15.97
Granted	60,000	41.08	41.08
Exercised	(157,464)	7.50 – 17.55	12.71
Employee transferred	(16,064)	10.69	10.69
Forfeited	(1,000)	14.01	14.01
Balance at December 31, 2007	1,323,614	$7.50 – $41.08	$17.57

The number of unvested stock options held by Market Resources employees increased by 47,500 shares to 260,000 in 2007.


	Options Outstanding			Options Exercisable		Unvested Options
Range of exercise prices	Number outstanding at Dec. 31, 2007	Weighted-average remaining term in years	Weighted-average exercise price	Number exercisable at Dec. 31, 2007	Weighted-average exercise price	Number unvested at Dec. 31, 2007	Weighted-average exercise price
$ 7.50 - $ 8.50	137,378	1.7	$ 7.96	137,378	$ 7.96
9.57 - 11.98	390,742	4.0	11.67	390,742	11.67
13.56 - 14.86	514,418	4.5	13.70	514,418	13.70
17.55 - 24.33	21,076	6.3	17.55	21,076	17.55
$38.57 - $41.08	260,000	5.4	39.15			260,000	$39.15
	1,323,614	4.3	$17.57	1,063,614	$12.29	260,000	$39.15

Most restricted share grants vest in equal installments over a three to four year period from the grant date. The weighted average vesting period of unvested restricted shares at December 31, 2007, was 15 months. Transactions involving restricted shares in the LTSIP in 2007 are summarized below:


	Restricted Shares Outstanding	Price Range	Weighted Average Price
Balance at January 1, 2006	354,482	$13.56 - $43.02	$20.64
Granted	231,580	35.20 - 44.77	37.10
Distributed	(121,326)	13.56 - 43.02	17.85
Forfeited	(4,990)	14.36 - 38.00	31.14
Balance at December 31, 2006	459,746	14.36 – 44.77	29.54
Granted	290,740	38.96 – 55.42	46.02
Distributed	(160,606)	14.36 – 49.98	23.40
Forfeited	(26,702)	18.45 – 49.97	35.22
Balance at December 31, 2007	563,178	$14.36 – $55.42	$39.40

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Note 3 – Asset Retirement Obligations (ARO)

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


	2007	2006
	(in millions)
ARO liability at January 1,	$128.3	$ 74.3
Accretion	8.1	6.9
Liabilities incurred	8.9	11.1
Revisions	1.5	38.2
Liabilities settled	(1.5)	(2.2)
ARO liability at December 31,	$145.3	$128.3

Wexpro activities are governed by the Wexpro Agreement. The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is spelled out in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the Public Service Commission of Wyoming (PSCW). Accordingly, Wexpro collects from Questar Gas and deposits in trust funds related to estimated ARO costs. The funds are used to satisfy retirement obligations as the properties are abandoned. At December 31, 2007, approximately $7.8 million was held in this trust invested primarily in a short-term bond index fund.

Note 4 – Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the period:


	2007	2006	2005
	(in millions)
Balance at January 1,	$10.5	$16.5	$14.6
Additions to capitalized exploratory well costs pending the
determination of proved reserves	1.5	10.5	9.8
Reclassifications to property, plant and equipment after the
determination of proved reserves		(5.0)	(5.7)
Capitalized exploratory well costs charged to expense, incurred in prior periods	(10.5)	(11.5)	(2.2)
Balance at December 31,	$ 1.5	$10.5	$16.5

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


	December 31,
	2007	2006	2005
	(in millions)
Capitalized exploratory well costs that have been capitalized
one year or less	$1.5	$10.5	$ 9.8
Capitalized exploratory well costs that have been capitalized
longer than one year			6.7
Balance at end of period	$1.5	$10.5	$16.5

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Note 5 – 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 $118.9 million with an interest rate of 5.36% and $142.6 million with an interest rate of 5.44% at December 31, 2007 and 2006, respectively.

All long-term notes and the term loan are unsecured obligations and rank equally with all other unsecured liabilities. Market Resources revolving credit agreement had $100 million outstanding at December 31, 2007 and zero a year earlier. This credit agreement carries an annual commitment fee of 0.115% of the unused balance. At December 31, 2007, Market Resources could pay dividends of $851.0 million without violating the terms of their debt covenants.

On May 11, 2006, Market Resources sold $250 million principal amount of 6.05% Notes due 2016. Net proceeds of $247 million were used for general corporate purposes including the June 14, 2006, early extinguishment of $200 million of 7% Notes due 2007. Market Resources recorded a $1.7 million charge related to the early extinguishment. Long-term debt outstanding as of December 31, 2007 and 2006 is listed in the table below:


	December 31,
	2007	2006
	(in millions)
7.5% notes due 2011	$150.0	$150.0
6.05% notes due 2016	250.0	250.0
Revolving term loan, 5.55% at December 31, due 2012	100.0
Total long-term debt outstanding	500.0	400.0
Less unamortized-debt discount	(0.7)	(0.8)
Total long-term debt outstanding	$499.3	$399.2

The Company’s 7.5% notes and revolving term loan are scheduled to be repaid within five years following December 31, 2007.

Note 6 – Financial Instruments and Risk Management

The carrying value and estimated fair values of Market Resources financial instruments were as follows:


	December 31, 2007		December 31, 2006
	Carrying	Estimated	Carrying	Estimated
	Value	Fair Value	Value	Fair Value
	(in millions)
*Financial assets*
Cash and cash equivalents			$ 18.2	$ 18.2
Notes receivable from Questar	$103.2	$103.2	69.8	69.8
Fair value of derivative contracts	85.9	85.9	204.5	204.5
*Financial liabilities*
Notes payable to Questar	118.9	118.9	142.6	142.6
Long-term debt	500.0	503.1	400.0	412.8
Fair value of derivative contracts	31.4	31.4	0.8	0.8

The Company used the following methods and assumptions in estimating fair values.

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

QUESTAR MARKET RESOURCES 2007 FORM 10-K

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

Derivative contracts – fair value of the contracts is based on market prices as posted on the NYMEX from the last trading day of the year. Gas derivatives are structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. As of December 31, 2007, Market Resources held gas-price-derivative instruments covering the price exposure for about 245.0 million MMBtu of natural gas, 2.0 million barrels of oil, 5.0 million gallons of NGL and basis-only swaps on an additional 40.8 Bcf. About $68.8 million of the fair value of all contracts as of December 31, 2007, will settle and be reclassified from other comprehensive income in the next 12 months. A year earlier Market Resources derivatives covered the price exposure for 204.2 million MMBtu of natural gas, 1.8 million barrels of oil, 22.7 million gallons of NGL and basis-only swaps on an additional 47.7 Bcf.

At December 31, 2007, the Company reported the fair value of derivative assets, net of liabilities, of $54.5 million. The offset to the net derivative assets, net of income taxes, was a $31.0 million unrealized gain on derivatives recorded in accumulated other comprehensive income in the Common Shareholder’s Equity section of the consolidated balance sheet. During 2007, $153.9 million of fair value associated with gas-price-derivative contracts settled and was reclassified into income. The ineffective portion of derivative transactions recognized in earnings was not significant. The fair-value calculation of gas- and oil-price derivatives does not consider changes in the fair value of the corresponding scheduled equity physical transactions, (i.e., the correlation between index price and the price realized for the physical delivery of gas or oil).

Note 7 – Income Taxes

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


	Year Ended December 31,
	2007	2006	2005
	(in millions)
Federal
Current	$ 56.4	$ 89.3	$ 65.5
Deferred	166.1	98.5	71.8
State
Current	1.9	6.6	5.4
Deferred	16.9	12.2	7.4
	$241.3	$206.6	$150.1

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,
	2007	2006	2005
Federal income tax statutory rate	35.0%	35.0%	35.0%
State income taxes, net of federal income tax benefit	1.8	2.2	2.0
Domestic production benefit	(0.3)	(0.4)	(0.3)
Percentage depletion		(0.1)	(0.1)
Other	(0.1)		0.2
Effective income tax rate	36.4%	36.7%	36.8%

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

QUESTAR MARKET RESOURCES 2007 FORM 10-K


	December 31,
	2007	2006
	(in millions)
*Deferred tax liabilities*
Property, plant and equipment	$744.7	$565.0
Energy-price derivatives		18.9
Total deferred tax liabilities	744.7	583.9
*Deferred tax assets*
Energy-price derivatives	6.0
Employee benefits and compensation costs	7.3	4.9
Total deferred tax assets	13.3	4.9
Net deferred income taxes	$731.4	$579.0
*Deferred income taxes – current liability*
Energy-price derivatives	$ 26.2	$ 58.3
Other	(12.9)	(16.6)
Deferred income taxes – current liability	$ 13.3	$ 41.7

Note 8 – Commitments and Contingencies

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


	(in millions)
2008	$ 8.7
2009	7.9
2010	7.6
2011	7.3
2012	5.3
2013 through 2028	18.7

Market Resources rents office space throughout its scope of operations from third-party lessors and leases space in an office building located in Salt Lake City, Utah from an affiliated company that expired October 31, 2007. The minimum future payments under the terms of long-term operating leases for the Company’s primary office locations for the six years following December 31, 2007, are as follows:

QUESTAR MARKET RESOURCES 2007 FORM 10-K


	(in millions)
2008	$3.6
2009	3.6
2010	3.3
2011	2.8
2012	1.8
2013	1.3

Total rental expense amounted to $3.0 million in 2007, $2.5 million in 2006 and $2.2 million in 2005.

Environmental Claims

In 2004, the Environmental Protection Agency (EPA) issued two separate compliance orders alleging that Gas Management did not comply with regulatory requirements adopted to implement the federal Clean Air Act. Both orders involved facilities in the Uinta Basin of eastern Utah that were purchased by Questar E&P in mid-2001. The EPA contends such facilities are located within “Indian Country” and are subject to federal Clean Air Act requirements, rather than air quality rules adopted by the state of Utah. Generally, EPA contends that Gas Management failed to obtain necessary pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations, in violation of federal requirements. Gas Management has generally contested EPA’s allegations, and believes that the permitting and regulatory requirements at issue can be legally avoided under Utah law. EPA has broadened its allegations to include additional potential ongoing violations of the Clean Air Act for the referenced facilities. Other Gas Management facilities in the Uinta Basin have been added to the civil penalty discussions with the EPA, with similar allegations of Clean Air Act violations. These potential violations will likely result in civil penalties of an unknown and undetermined amount in excess of $100,000. The parties are engaged in settlement discussions and have signed a tolling agreement to extend the statute of limitations for filing any claims. Because of the complexities and uncertainties of this dispute, it is difficult to predict the likely potential outcomes; however, management believes the company has accrued an appropriate liability for this claim.

Note 9 – 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 $4.6 million in 2007, $4.9 million in 2006 and $3.3 million in 2005.

Market Resources portion of plan assets and benefit obligations can not 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, 2007 and 2006, Questar’s projected benefit obligation exceeded the fair value of plan assets.

Postretirement Benefits Other Than Pensions

Eligible Market Resources employees participate in Questar’s postretirement benefits other than pensions plan. Postretirement health care benefits and life insurance are provided only to employees hired before January 1, 1997. The Company pays a portion of the costs of health care benefits, based on an employee’s years of service, and generally limits payments to 170% of the 1992 contribution. Plan assets consist of equity securities and corporate and U.S. government debt obligations. A third party consultant calculates the projected benefit obligation. The cost of postretirement benefits other than pensions was $1.3 million in 2007 and 2006 and $1.2 million in 2005.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

The Company’s portion of plan assets and benefit obligations related to post-retirement medical and life insurance benefits can not be determined because the plan assets are not segregated or restricted to meet the Company’s obligations. At December 31, 2007 and 2006, Questar’s accumulated benefit obligation exceeded the fair value of plan assets.

Employee Investment Plan

Market Resources subsidiaries participate in Questar’s Employee Investment Plan (EIP).The EIP allows eligible employees to purchase shares of Questar common stock or other investments through payroll deduction at the current fair market value on the transaction date. The Company currently contributes an overall match of 100% of employees’ pre-tax purchases up to a maximum of 6% of their qualifying earnings. In addition, the Company contributes $200 annually to the EIP for each eligible employee. Beginning in 2005, the EIP trustee purchased Questar shares on the open market as cash contributions are received. The Company’s expense equaled its matching contribution of $3.5 million in 2007, $2.4 million in 2006 and $2.1 million in 2005.

Note 10 – Related Party Transactions

Market Resources receives a portion of its revenues from services provided to affiliate, Questar Gas. The Company received $171.6 million in 2007, $176.4 million in 2006 and $159.5 million in 2005 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 11).

Market Resources pays Questar for certain administrative services. These payments were $16.8 million in 2007, $11.5 million in 2006 and $13.0 million in 2005 and were included in operating expenses. 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 paid $2.8 million in 2007, $3.7 million in 2006 and $2.8 million in 2005 for these services. Energy Trading purchased and marketed liquids extracted from Questar Pipeline’s transportation lines in 2005 paying $3.6 million. Questar InfoComm, an affiliated company that previously provided some information technology and communication services to Market Resources was paid $0.2 million in 2005.

Market Resources has a lease with Questar for space in an office building located in Salt Lake City, Utah, that expired October 31, 2007. 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 paid $1.0 million in 2007, $0.7 million in 2006 and $0.8 million in 2005.

The Company received interest income from affiliated companies of $4.5 million in 2007, $3.4 million in 2006 and $0.8 million in 2005. Market Resources incurred interest expense to affiliated companies of $6.8 million in 2007, $4.4 million in 2006 and $3.8 million in 2005.

Note 11 – Wexpro Agreement

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

a. Wexpro conducts gas-development drilling on a finite group of productive gas properties, as defined in the agreement, and bears any costs of dry holes. Natural gas produced from successful drilling on these properties is delivered to Questar Gas. Wexpro is reimbursed for the costs of producing the natural gas plus a return on its investment in successful wells. The after-tax return allowed Wexpro is adjusted annually and is approximately 20.9%.

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 12.9%.

c. Production from a finite group of oil-producing properties is sold at market prices with the revenues used to recover operating expenses and to give Wexpro a return on its investment. The after-tax rate of return is adjusted annually and is approximately

QUESTAR MARKET RESOURCES 2007 FORM 10-K

12.9%. Any net income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%.

d. Wexpro conducts developmental-oil drilling on productive oil properties and bears any costs of dry holes. Oil discovered from these properties is sold at market prices with the revenues used to recover operating expenses and to give Wexpro a return on its investment in successful wells. The after-tax rate of return is adjusted annually and is approximately 17.9%. Any net income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas with Wexpro retaining 46%. Questar Gas received oil-income sharing of $4.9 million in 2007, $5.5 million in 2006 and $6.1 million in 2005.

e. 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 investment base, net of depreciation and deferred income taxes, and the yearly average rate of return for 2007 and the previous two years are shown in the table below:


	2007	2006	2005
Wexpro’s net investment base (in millions)	$300.4	$260.6	$206.3
Average annual rate of return (after tax)	19.9%	19.9%	20.4%

Note 12 – 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, 2007:


	Market Resources Consolidated	Interco. Transactions	Questar E&P	Wexpro	Gas Management	Energy Trading

	(in millions)
*2007*
Revenues
From unaffiliated customers	$1,671.3		$ 956.0	$ 21.6	$189.3	$504.4
From affiliated companies	172.1	($484.7)		155.7	17.0	484.1
Total Revenues	1,843.4	(484.7)	956.0	177.3	206.3	988.5
Operating expenses
Cost of natural gas and other products sold	474.7	(482.8)	2.2			955.3
Operating and maintenance	187.9	(1.1)	87.9	16.5	83.6	1.0
General and administrative	91.3	(0.8)	56.3	14.7	17.2	3.9
Production and other taxes	81.6		60.1	20.0	1.4	0.1
Depreciation, depletion and amortization	295.1		243.5	31.2	19.1	1.3
Other operating expenses	38.1		32.8	4.9	0.4
Total operating expenses	1,168.7	(484.7)	482.8	87.3	121.7	961.6
Net (loss) from asset sales	(1.3)		(0.6)	(0.7)
Operating income	673.4		472.6	89.3	84.6	26.9
Interest and other income	15.4	(26.9)	6.2	1.9	0.2	34.0
Income from unconsolidated affiliates	8.9		0.4		8.5
Interest expense	(35.6)	26.9	(25.2)	(2.0)	(6.9)	(28.4)
Income tax expense	(241.3)		(168.5)	(30.0)	(31.1)	(11.7)

QUESTAR MARKET RESOURCES 2007 FORM 10-K


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
Capital expenditures	943.9		708.5	105.0		128.3		2.1
Goodwill	60.9		60.9
*2006*
Revenues
From unaffiliated customers	$1,659.4		$ 815.7		$ 19.7		$168.0		$ 656.0
From affiliated companies	176.4	($687.8)			150.5		15.9		697.8
Total Revenues	1,835.8	(687.8)	815.7		170.2		183.9		1,353.8
Operating expenses
Cost of natural gas and other products sold	652.6	(686.0)	2.8						1,335.8
Operating and maintenance	180.4	(1.1)	73.6		14.7		92.4		0.8
General and administrative	69.2	(0.7)	42.4		11.3		12.2		4.0
Production and other taxes	89.4		58.3		30.3		0.6		0.2
Depreciation, depletion and amortization	235.0		185.7		33.1		15.3		0.9
Other operating expenses	47.5		42.0		5.5
Total operating expenses	1,274.1	(687.8)	404.8		94.9		120.5		1,341.7
Net gain (loss) from asset sales	25.2		24.3		(0.1)		1.0
Operating income	586.9		435.2		75.2		64.4		12.1
Interest and other income (expense)	2.2	(27.0)	(3.7)		1.3				31.6
Income from unconsolidated affiliates	7.5		0.4				7.1
Interest expense	(33.9)	27.0	(27.1)		(0.5)		(4.7)		(28.6)
Income tax expense	(206.6)		(150.9)		(26.0)		(24.2)		(5.5)
Net income	$ 356.1		$ 253.9		$ 50.0		$ 42.6		$ 9.6
Identifiable assets	$3,249.6		$2,169.9		$397.1		$377.1		$305.5
Investment in unconsolidated affiliates	37.5						37.3		0.2
Capital expenditures	752.7		586.3		82.7		82.2		1.5
Goodwill	60.9		60.9
*200*5
Revenues
From unaffiliated customers	$1,668.7		$ 620.6		$ 21.7		$ 141.5		$ 884.9
From affiliated companies	159.5	($618.9)			132.3		13.7		632.4
Total Revenues	1,828.2	(618.9)	620.6		154.0		155.2		1,517.3
Operating expenses
Cost of natural gas and other products sold	888.3	(617.6)	4.2						1,501.7
Operating and maintenance	158.6	(0.6)	61.8		11.2		85.2		1.0
General and administrative	54.6	(0.7)	33.9		10.0		7.5		3.9
Production and other taxes	102.2		68.7		32.6		0.7		0.2
Depreciation, depletion and amortization	173.8		134.7		26.9		11.3		0.9
Other operating expenses	25.5		18.8		6.7
Total operating expenses	1,403.0	(618.9)	322.1		87.4		104.7		1,507.7
Net gain (loss) from asset sales	0.9		1.1		(0.2)
Operating income	426.1		299.6		66.4		50.5		9.6

QUESTAR MARKET RESOURCES 2007 FORM 10-K


Interest and other income	5.6	(26.2)	0.6	0.9	0.3	30.0
Income from unconsolidated affiliates	7.5		0.3		7.2
Interest expense	(30.9)	26.2	(23.7)	(0.1)	(3.1)	(30.2)
Income tax expense	(150.1)		(104.0)	(23.5)	(19.2)	(3.4)
Net income	$ 258.2		$ 172.8	$ 43.7	$ 35.7	$ 6.0
Identifiable assets	$2,621.3		$1,656.7	$ 331.2	$ 301.8	$ 331.6
Investment in unconsolidated affiliates	30.7		0.1		30.3	0.3
Capital expenditures	576.2		424.2	57.8	93.3	0.9
Goodwill	61.5		61.5

Note 13 – Subsequent Event - Questar E&P Property Acquisition

On January 31, 2008, Questar E&P entered into agreements with multiple private sellers to acquire two significant natural gas development properties in northwest Louisiana for an aggregate purchase price of $655 million. The transactions will be subject to usual and customary closing and post-closing adjustments. In February 2008, Market Resources established a $700 million floating-rate term-loan credit facility, due August 15, 2008, to finance the purchase of the Louisiana natural gas development properties. Market Resources plans to expand its current revolving credit facility to $800 million and issue up to $500 million of additional long-term debt to retire the $700 million term loan credit facility.

Note 14 – Quarterly Financial Information (Unaudited)

Following is a summary of quarterly financial information:


	First	Second	Third	Fourth
	Quarter	Quarter	Quarter	Quarter	Year
	(in millions)
*2007*
Revenues	$478.7	$430.6	$411.8	$522.3	$1,843.4
Operating income	165.5	173.1	167.7	167.1	673.4
Net income	109.5	102.1	108.7	100.5	420.8
2006
Revenues	$467.5	$424.3	$467.9	$476.1	$1,835.8
Operating income	155.0	138.6	156.2	137.1	586.9
Net income	94.7	79.3	92.0	90.1	356.1

Note 15 – Supplemental Gas and Oil Information (Unaudited)

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 2007 FORM 10-K


	December 31,
	2007	2006
	(in millions)
Proved properties	$3,306.9	$2,646.6
Unproved properties	55.6	42.7
Support equipment and facilities	23.3	18.5
	3,385.8	2,707.8
Accumulated depreciation, depletion and amortization	(1,114.3)	(901.5)
	$2,271.5	$1,806.3

Costs Incurred

The costs incurred in gas and oil exploration and development activities are displayed in the table below. The development costs include expenditures to develop a portion of the proved undeveloped reserves reported at the end of the prior year. These costs were $125.8 million in 2007, $109.2 million in 2006 and $116.7 million in 2005.


	Year Ended December 31,
	2007	2006	2005
	(in millions)
Property acquisition
Unproved	$ 28.9	$ 22.5	$13.7
Proved	45.1	20.6	3.4
Exploration (capitalized and expensed)	25.4	34.5	49.4
Development	641.7	581.2	381.7
	$741.1	$658.8	$448.2

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,
	2007	2006	2005
	(in millions)
Revenues	$956.0	$815.7	$620.6
Production expenses	148.0	131.9	130.5
Exploration expenses	22.0	34.4	11.1
Depreciation, depletion and amortization	243.5	185.7	134.7
Abandonment and impairment	10.8	7.6	7.7
Total expenses	424.3	359.6	284.0
Revenues less expenses	531.7	456.1	336.6
Income taxes	(197.3)	(170.1)	(126.6)
Results of operation before corporate overhead and interest expenses	$334.4	$286.0	$210.0

Estimated Quantities of Proved Gas and Oil Reserves

Estimates of the Company’s proved gas and oil reserves have been prepared by Ryder Scott Company, H. J. Gruy and Associates, Inc. and Netherland, Sewell & Associates, Inc., independent reservoir engineers, in accordance with the SEC’s Regulation S-X and SFAS 69 “Disclosures about Oil and Gas Producing Activities.” The table below summarizes the changes in

QUESTAR MARKET RESOURCES 2007 FORM 10-K

the estimated net quantities of proved natural gas, oil and NGL reserves for each of the three years in the period ended December 31, 2007. The quantities reported are based on existing economic and operating conditions at the time the estimates were made. All gas and oil reserves reported are located in the United States. The Company does not have any long-term supply contracts with foreign governments or reserves of equity investees.


			Natural Gas
	Natural Gas	Oil and NGL	Equivalents
	(Bcf)	(MMbbl)	(Bcfe)⁽^a⁾
*Proved Reserves*
Balance at January 1, 2005	1,270.5	27.2	1,434.0
Revisions -
Previous estimates	11.9	(0.7)	7.9
Pinedale increased-density⁽^b⁾	31.5	0.3	33.0
Extensions and discoveries	110.9	1.4	119.3
Purchase of reserves in place	0.3	0.1	0.7
Sale of reserves in place	(0.3)		(0.3)
Production	(100.0)	(2.4)	(114.2)
Balance at December 31, 2005	1,324.8	25.9	1,480.4
Revisions -
Previous estimates	(38.9)	2.6	(23.8)
Pinedale increased-density⁽^b⁾	163.0	1.2	170.4
Extensions and discoveries	119.1	1.2	126.6
Purchase of reserves in place	9.8	0.1	10.2
Sale of reserves in place	(2.7)		(2.8)
Production	(113.9)	(2.6)	(129.6)
Balance at December 31, 2006	1,461.2	28.4	1,631.4
Revisions -
Previous estimates	26.3	3.3	46.2
Pinedale increased-density⁽^b⁾	120.6	1.0	126.8
Extensions and discoveries	172.6	3.3	192.7
Purchase of reserves in place	16.0	0.2	17.1
Sale of reserves in place	(6.3)		(6.4)
Production	(121.9)	(3.0)	(140.2)
Balance at December 31, 2007	1,668.5	33.2	1,867.6

*Proved-Developed Reserves*
Balance at January 1, 2005	680.6	21.3	808.3
Balance at December 31, 2005	792.0	21.4	920.5
Balance at December 31, 2006	852.0	23.1	990.7
Balance at December 31, 2007	987.4	26.7	1,147.4

^(a)Natural Gas Equivalents – oil volumes are converted to natural gas equivalents using the ratio of one barrel of crude oil, condensate or NGL to 6,000 cubic feet of natural gas.

^(b)Estimates of the quantity of proved reserves from the Company’s Pinedale Anticline leasehold in western Wyoming have changed substantially over time as a result of numerous factors including, but not limited to, additional development drilling activity, producing well performance and an improved understanding of Lance Pool reservoir characteristics. The continued

QUESTAR MARKET RESOURCES 2007 FORM 10-K

analysis of new data has led to progressive increases in estimates of original gas-in-place in the Lance Pool reservoirs at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. The WOGCC has approved 10-acre-density drilling for Lance Pool wells on about 12,700 (gross) of the Company’s 18,208 acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the estimated productive limits of the Company’s core acreage in the field. In January 2008, the WOGCC approved five-acre-density drilling for Lance Pool wells on about 4,200 gross acres of Market Resources Pinedale leasehold. If five-acre-density development is appropriate for a majority of its leasehold, the company currently estimates up to an additional 1,600 wells will be required to fully develop the Lance Pool on its acreage. The Company will continue to disclose future revisions to proved reserves associated with Pinedale increased-density drilling separately.

Standardized Measure of Future Net Cash Flows Relating to Proved Reserves

Future net cash flows were calculated at December 31 using year-end prices and known contract-price changes. The year-end prices do not include any impact of hedging activities. The average year-end price per Mcf of proved natural gas reserves was $6.01 in 2007, $4.47 in 2006 and $7.80 in 2005. The average year-end price per barrel of proved oil and NGL reserves combined was $80.86 in 2007, $51.49 in 2006 and $56.47 in 2005. 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 $230.7 million in 2008, $299.7 million in 2009 and $159.7 million in 2010. At the end of this three-year period the Company expects to have evaluated about 53% 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.


	Year Ended December 31,
	2007	2006		2005
	(in millions)
Future cash inflows	$12,704.3	$ 7,985.1	$11,791.1
Future production costs	(2,863.4)	(2,133.0)	(2,465.8)
Future development costs	(1,232.4)	(1,026.9)	(725.7)
Future income tax expenses	(2,668.8)	(1,396.2)	(2,930.3)
Future net cash flows	5,939.7	3,429.0	5,669.3
10% annual discount to reflect timing of net cash flows	(3,105.7)	(1,861.2)	(2,962.2)
Standardized measure of discounted future net cash flows	$ 2,834.0	$ 1,567.8	$ 2,707.1

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


	Year Ended December 31,
	2007	2006	2005
	(in millions)
Balance at January 1,	$1,567.8	$2,707.1	$1,760.5
Sales of gas and oil produced, net of production costs	(808.0)	(683.8)	(490.1)
Net changes in prices and production costs	1,554.6	(1,994.3)	1,183.6
Extensions and discoveries, less related costs	523.6	233.1	330.4
Revisions of quantity estimates	470.0	269.9	113.3
Net purchases and sales of reserves in place	41.8	(7.5)	0.5

QUESTAR MARKET RESOURCES 2007 FORM 10-K


Cost to develop proved undeveloped reserves	125.8	109.2	116.7
Change in future development	(214.5)	(259.6)	(120.3)
Accretion of discount	221.0	411.0	176.1
Net change in income taxes	(635.0)	760.8	(440.3)
Other	(13.1)	21.9	76.7
Net change	1,266.2	(1,139.3)	946.6
Balance at December 31,	$2,834.0	$1,567.8	$2,707.1

Cost-of-Service Activities

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

Capitalized Costs

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


	December 31,
	2007	2006
	(in millions)
Wexpro	$434.7	$353.2
Questar Gas	12.2	13.2
	$446.9	$366.4

Costs Incurred

Costs incurred by Wexpro for cost-of-service gas and oil-producing activities were $110.7 million in 2007, $100.3 million in 2006 and $57.0 million in 2005.

Results of Operation

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


	Year Ended December 31,
	2007	2006	2005
	(in millions)
Revenues
From unaffiliated companies	$ 21.6	$ 19.7	$ 21.7
From affiliates^(a)	155.7	150.5	132.3
Total revenues	177.3	170.2	154.0
Production expenses	41.4	50.5	50.0
Depreciation and amortization	31.2	33.1	26.9
Abandonment and impairment			0.2
Exploration			0.4
Total expenses	72.6	83.6	77.5
Revenues less expenses	104.7	86.6	76.5
Income taxes	(35.2)	(29.6)	(26.8)
Results of operation before corporate overhead and interest expense	$ 69.5	$ 57.0	$ 49.7

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

QUESTAR MARKET RESOURCES 2007 FORM 10-K

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

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


			Natural Gas
	Natural Gas	Oil and NGL	Equivalents
	(Bcf)	(MMbbl)	(Bcfe)^(a)
*Proved Reserves*
Balance at January 1, 2005	531.1	4.2	556.3
Revisions-
Previous estimates	(30.8)	(0.1)	(32.2)
Pinedale increased-density^(b)	7.8		8.1
Extensions and discoveries	29.2	0.2	30.7
Production	(40.0)	(0.4)	(42.4)
Balance at December 31, 2005	497.3	3.9	520.5
Revisions-
Previous estimates	22.3	(0.1)	21.5
Pinedale increased-density^(b)	100.0	0.8	104.6
Extensions and discoveries	39.8	0.2	41.3
Production	(38.8)	(0.4)	(40.9)
Balance at December 31, 2006	620.6	4.4	647.0
Revisions-
Previous estimates	(29.9)		(30.0)
Pinedale increased-density^(b)	24.6	0.2	25.9
Extensions and discoveries	35.5	0.1	36.4
Production	(34.9)	(0.4)	(37.4)
Balance at December 31, 2007	615.9	4.3	641.9

*Proved-Developed Reserves*
Balance at January 1, 2005	409.2	3.2	428.4
Balance at December 31, 2005	406.6	3.1	425.2
Balance at December 31, 2006	440.6	2.9	458.2
Balance at December 31, 2007	439.4	2.9	456.9

^(a) Natural Gas Equivalents – oil volumes are converted to natural gas equivalents using the ratio of one barrel of crude oil, condensate or NGL to 6,000 cubic feet of natural gas.

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

QUESTAR MARKET RESOURCES 2007 FORM 10-K


QUESTAR MARKET RESOURCES, INC.
Schedule of Valuation and Qualifying Accounts

		Column C		Column D
Column A	Column B	Amounts charged		Deductions for	Column E
Description	Beginning Balance	to expense		accounts written off	Ending Balance
(in millions)
Year Ended December 31, 2007
Allowance for bad debts	$4.3		$0.1	($1.1)	$3.3
Year Ended December 31, 2006
Allowance for bad debts	2.9		1.4		4.3
Year Ended December 31, 2005
Allowance for bad debts	2.8		0.1		2.9

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.

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 (the Exchange Act)) as of December 31, 2007, covered by the report (the Evaluation Date). The effectiveness of the Company’s internal control over financial reporting was assessed using criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework. Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the Company’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company, including its consolidated subsidiaries, required to be included in the Company’s reports filed or submitted under the Exchange Act. The Company’s Chief Executive Officer and Chief Financial Officer also concluded that the controls and procedures were effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management including its principal executive and financial officers or persons performing similar functions as appropriate to allow timely decisions regarding required disclosure.

This annual report is not required to and does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.

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, 2007 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). The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. 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, 2007, is effective based on those criteria.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

ITEM 9B. OTHER INFORMATION.

None.

PART III

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:


	2007	2006
Audit Fees	$1,217,900	$1,392,407
Market Resources Portion	681,081	824,370
Audit-related Fees	95,000	90,000
Market Resources Portion	54,839	44,647
Tax Fees	10,113	11,453
Market Resources Portion	5,814	2,751
All Other Fees	295,455	-
Market Resources Portion	7,280	-

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. (Incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 11, 2006.)

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.)

QUESTAR MARKET RESOURCES 2007 FORM 10-K

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.

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 Form 10-K Annual Report 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.)

12.

Ratio of earnings to fixed charges.

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 S. E. Parks, Questar Market Resources, Inc. 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 S. E. Parks, Questar Market Resources, Inc. President and Chief Executive Officer and 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.

QUESTAR MARKET RESOURCES 2007 FORM 10-K

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 27th day of February, 2008.

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/S. E. Parks

Vice President and Chief Financial

S. E. Parks

Officer (Principal Financial Officer)

/s/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

February 27, 2008

*By

/s/C. B. Stanley

Date

C. B. Stanley, Attorney in Fact

QUESTAR MARKET RESOURCES 2007 FORM 10-K

Exhibits List

Exhibit No.

Description

1.1.*

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.*

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.)

4.1.*¹

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.*

4.4.*

4.5

Term Credit Agreement dated February 15, 2008, by and among the Company and Bank of America, N.A.

10.1.*

10.2.*

10.3.*

10.4.*

10.5.*

10.6.*

QUESTAR MARKET RESOURCES 2007 FORM 10-K

12.

Ratio of earnings to fixed charges.

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 S. E. Parks, Questar Market Resources, Inc. Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.

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

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

QUESTAR MARKET RESOURCES 2007 FORM 10-K