10-K

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

QUESTAR CORPORATION
(Exact name of registrant as specified in charter)

STATE OF UTAH	1-8796	87-0407509
(State or other jurisdiction of incorporation or organization	(Commission File No.)	(I.R.S. Employer Identification No.)

180 East 100 South, P.O. Box 45433, Salt Lake City, Utah 84145-0433

(Address of principal executive offices)

Registrant’s telephone number:  (801) 324-5699

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

Common stock without par value

The above Securities are listed on the New York Stock Exchange

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

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

Yes  [X]

No  [  ]

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

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):  $9.1 billion.*

On January 31, 2008, 172,795,826 shares of the registrant’s common stock, without par value, were outstanding.

Documents Incorporated by Reference. Portions of the Registrant’s Definitive Proxy Statement (the “Proxy Statement”) to be filed with respect to its Annual Meeting of Shareholders scheduled to be held on May 20, 2008.

*Calculated by excluding all shares held by directors and executive officers of registrant and three nonprofit foundations established by registrant without conceding that all such persons are affiliates for purposes of federal securities laws.

QUESTAR 2007 FORM 10-K

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TABLE OF CONTENTS

Page No.

4

4

5

Nature of Business

7

Market Resources

8

Exploration and Production

8

     Questar E&P

8

     Wexpro

8

Midstream Field Services – Questar Gas Management

9

Energy Marketing – Questar Energy Trading

10

Interstate Gas Transportation – Questar Pipeline

10

Retail Gas Distribution – Questar Gas

11

Corporate

12

Environmental Matters

12

Employees

12

Executive Officers

12

13

16

Exploration and Production

16

     Questar E&P

16

     Wexpro

17

Midstream Field Services – Questar Gas Management

20

Energy Marketing – Questar Energy Trading

20

Interstate Gas Transportation – Questar Pipeline

20

Retail Gas Distribution – Questar Gas

20

21

21

21

23

24

38

41

76

77

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79

79

80

79

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,

AND DIRECTOR INDEPENDENCE

79

79

80

83

Where You Can Find More Information

Questar Corporation (Questar) and its principal subsidiaries, Questar Market Resources, Inc., Questar Pipeline Company and Questar Gas Company, each file annual, quarterly, and current reports with the Securities and Exchange Commission (SEC). Questar also regularly files proxy statements and other documents with the 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.

Investors can also access financial and other information via Questar’s web site at www.questar.com. Questar and each of its reporting subsidiaries 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 and all reports filed by executive officers and directors under Section 16 of the Exchange Act reporting transactions in Questar securities. 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 its 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 Questar, 180 East 100 South Street, P.O. Box 45433, Salt Lake City, Utah 84145-0433 (telephone number (801) 324-5000).

Forward-Looking Statements

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

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·

changes in industry trends;

·

changes in laws or regulations; and

·

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

Questar 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

B

Billion.

bbl

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

basis

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

basis-only swap

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

Btu

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

cash flow hedge

A derivative instrument that complies with 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.

cf

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

cfe

Cubic feet of natural gas equivalents.

development well

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

dewpoint

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

dry hole

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

dth

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

dthe

Decatherms of natural gas equivalents.

equity production

Production at the wellhead attributed to 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.

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heating degree days

A measure of the number of degrees the average daily outside temperature is below 65 degrees Fahrenheit.

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.

M

Thousand.

MM

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).

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.

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FORM 10-K

ANNUAL REPORT, 2007

PART I

ITEM 1.  BUSINESS

Nature of Business

Questar Corporation (Questar or the Company) is a natural gas-focused energy company with five major lines of business – gas and oil exploration and production, midstream field services, energy marketing, interstate gas transportation, and retail gas distribution – which are conducted through its three principal subsidiaries:

·

Questar Market Resources, Inc. (Market Resources) is a subholding company that operates through 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. Questar Energy Trading Company (Energy Trading) markets equity and third-party natural gas and oil, provides risk-management services and owns and operates an underground gas-storage reservoir.

·

Questar Pipeline Company (Questar Pipeline) provides interstate natural gas transportation and storage and other energy services.

·

Questar Gas Company (Questar Gas) provides retail natural gas distribution services in Utah, Wyoming and Idaho.

Questar operates in the Rocky Mountain and Midcontinent regions of the United States of America and is headquartered in Salt Lake City, Utah. Shares of Questar common stock trade on the New York Stock Exchange under the symbol STR.

Questar is a holding company, as that term is defined in the Public Utility Holding Company Act of 2005 (PUHCA 2005), because its subsidiary Questar Gas is a natural gas utility company. Questar, however, has an exemption and waiver from provisions of the Act applicable to holding companies. Questar conducts all operations through subsidiaries. The parent holding company performs certain management, legal, tax, administrative and other services for its subsidiaries.

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

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

Exploration and Production – Questar E&P and Wexpro

General: Questar’s exploration and production business is conducted through Questar E&P and Wexpro. Exploration and production generated approximately 67% 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 p urchase 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 16 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company’s proved reserves.

Wexpro 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 base totaled $300.4 million at December 31, 2007. See Note 13 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Wexpro Agreement.

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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 generated approximately 10% 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 the Muddy Creek compressor station owned by Kern River Gas Transmission Co.’s (Kern River Pipeline).

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-

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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 3% 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 9 to the consolidated financial statements included in Item 8 and in Item 7A of Part II of this Annual Report for additional information relating to hedging activities.

Interstate Gas Transportation – Questar Pipeline

General: Questar Pipeline and subsidiaries, generated approximately 11% of the Company’s operating income in 2007. Questar Pipeline provides natural gas-transportation and underground storage services in Utah, Wyoming and Colorado. As a “natural gas company” under the Natural Gas Act of 1938, Questar Pipeline and certain subsidiary pipeline companies are regulated by the FERC as to rates and charges for storage and transportation of natural gas in interstate commerce, construction of new facilities, and extensions or abandonments of service and facilities, accounting and other activities.

Questar Pipeline and its subsidiaries own 2,505 miles of interstate pipeline with total daily capacity of 4,006 Mdth. Questar Pipeline’s core-transmission system is strategically located in the Rocky Mountain area near large reserves of natural gas in six major Rocky Mountain producing areas. Questar Pipeline transports natural gas from these producing areas to other major pipeline systems and to the Questar Gas distribution system. In addition to this core system, Questar Pipeline, through wholly-owned subsidiaries, owns and operates the Overthrust Pipeline in southwestern Wyoming and the eastern segment of Southern Trails Pipeline, a 488-mile line that extends from the Blanco hub in the San Juan Basin to just inside the California state line. An additional 165 miles of Southern Trails Pipeline in California is not in service.

Questar Pipeline owns and operates the Clay Basin storage facility, the largest underground- storage reservoir in the Rocky Mountain region. Through a subsidiary, Questar Pipeline also owns gathering lines and processing plants near Price, Utah, which provides heat-content-management services for Questar Gas and carbon-dioxide extraction and gas-processing services for third parties.

Customers, Growth and Competition: Questar Pipeline’s transportation system is nearly fully subscribed. The weighted-average remaining life of firm contracts on Questar Pipeline was 6.9 years as of December 31, 2007. All of Questar Pipeline storage capacity is fully contracted with a weighted-average remaining life of 7.3 years as of December 31, 2007. Questar Pipeline faces the risk that it may not be able to recontract firm capacity when contract terms expire.

Questar Gas, an affiliated company, remains Questar Pipeline’s largest transportation customer. During 2007, Questar Pipeline transported 113.8 MMdth for Questar Gas compared to 116.7 MMdth in 2006. Questar Gas has reserved firm-transportation capacity of 901 Mdth per day under long-term contracts, or about 50% of Questar Pipeline’s reserved capacity. Questar Pipeline’s primary transportation agreement with Questar Gas will expire on June 30, 2017.

Questar Pipeline also transported 352.3 MMdth during 2007 for nonaffiliated customers to pipelines owned by Kern River Pipeline, Northwest Pipeline, Colorado Interstate Gas, TransColorado, Wyoming Interstate Company and other systems. Rocky Mountain producers, marketers and end-users seek capacity on interstate pipelines that move gas to California, the Pacific

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Northwest or Midwestern markets. Questar Pipeline provides access for many producers to these third-party pipelines. Some parties, including Gas Management, an affiliate of Questar, are building gathering lines that allow producers to make direct connections to competing pipeline systems.

During 2007, Questar Pipeline completed an 80-mile expansion of its Overthrust Pipeline from Kanda to Wamsutter, Wyoming. Questar Pipeline placed this expansion into service in mid-December 2007. The $202 million investment for this expansion project was underwritten by a long-term capacity lease and long-term contracts. Questar Pipeline also completed a $109 million 59-mile expansion of its southern system in central Utah. This project is also supported with long-term contracts.

Regulation:  On January 18, 2007, the FERC proposed permanent standards of conduct regulation in a Notice of Proposed Rulemaking (NOPR) that will replace an Interim Rule governing the relationship between transmission providers and their energy affiliates. The Interim Rule was put forth by the FERC in January 2007 in response to a November 2006 decision by the U.S. Court of Appeals for the District of Columbia Circuit vacating Order 2004. The Court found that the FERC had not adequately supported the application of the standards of conduct to a broader definition of energy affiliates in Order No. 2004. In its NOPR the FERC proposed that the standards of conduct apply only to marketing affiliates. The proposed definition of marketing affiliate is similar to the definition found in the FERC’s prior Order No. 497.

Questar Pipeline is required to comply with the Pipeline Safety Improvement Act of 2002. This Act and the rules issued by the DOT require interstate pipelines and local distribution companies to implement a 10-year program of risk analysis, pipeline assessment and remedial repair for transportation pipelines located in high-consequence areas such as densely-populated locations. Questar Pipeline’s annual cost to comply with the Act is approximately $1 million, not including costs of pipeline replacement, if necessary.

Retail Gas Distribution - Questar Gas

General: Questar Gas distributes natural gas as a public utility in Utah, southwestern Wyoming and a small portion of southeastern Idaho. It generated approximately 9% of the Company’s operating income in 2007. As of December 31, 2007, Questar Gas was serving 873,607 sales and transportation customers. Questar Gas is the only non-municipal gas-distribution utility in Utah, where over 96% of its customers are located. The Public Service Commission of Utah (PSCU), the Public Service Commission of Wyoming (PSCW) and the Public Utility Commission of Idaho have granted Questar Gas the necessary regulatory approvals to serve these areas. Questar Gas also has long-term franchises granted by communities and counties within its service area.

Questar Gas growth is tied to the economic growth of Utah and southwestern Wyoming. It has over 90% of the load for residential space heating and water heating in its service area. During 2007, Questar Gas added 23,065 customers, a 3% increase.

Questar Gas faces the same risks as other local-distribution companies. These risks include revenue variations based on seasonal changes in demand, sufficient gas supplies, declining residential usage per customer, adequate distribution facilities and adverse regulatory decisions. Questar Gas’s sales to residential and commercial customers are seasonal, with a substantial portion of such sales made during the heating season. The typical residential customer in Utah (defined as a customer using 80 dth per year) consumes over 77% of total gas requirements in the coldest six months of the year. Questar Gas, however, has a weather-normalization mechanism for its general-service customers. This mechanism adjusts the non-gas portion of a customer’s monthly bill as the actual heating-degree days in the billing cycle are warmer or colder than normal. This mechanism reduces dramatic fluctuations in any given customer’s monthly bill from year to year and reduces fluctuations in Que star Gas gross margin.

In October 2006, the PSCU approved a pilot program for a conservation enabling tariff (CET) effective January 1, 2006, to promote energy conservation. Under the Company’s prior rate structure, non-gas revenues declined when average temperature adjusted usage per customer declined while non-gas revenues increased when average temperature adjusted usage per customer increased. Under the CET, Questar Gas non-gas revenues are decoupled from the temperature adjusted usage per customer. The tariff specifies a margin per customer for each month with differences to be deferred and recovered from customers or refunded to customers through periodic rate adjustments. These adjustments are limited to five percent of distribution non-gas revenues. Under the CET, Questar Gas recorded a $2.5 million revenue increase in 2007 as a result of a 2% decline in usage per customer. In late 2007, the PSCU ordered a continuation of the CET program for an additional two years.

In January 2007, the PSCU approved a demand-side management program (DSM) effective January 1, 2007. Under the DSM, Questar Gas encourages the conservation of natural gas through advertising, rebates for efficient homes and appliances, and energy audits. The costs related to the DSM are deferred and recovered from customers through periodic rate adjustments. Questar Gas incurred recoverable DSM costs of $7.6 million in 2007.

Questar Gas minimizes gas supply risk with cost-of-service natural gas reserves. During 2007, Questar Gas satisfied 34% of its supply requirements with cost-of-service gas and associated royalty-interest volumes. Wexpro produces cost-of-service gas,

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which is then gathered by Gas Management and transported by Questar Pipeline. See Item 2 of Part I and Note 16 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company’s cost-of-service proved reserves. Questar Gas also has a balanced and diversified portfolio of gas-supply contracts for volumes produced in Wyoming, Colorado, and Utah. Questar Gas has regulatory approval to pass through the costs associated with hedging activities in its balancing account.

Questar Gas has designed its distribution system and annual gas-supply plan to handle design-day demand, which is defined as the estimated volume of gas that firm customers could use when the weather is extremely cold. For the 2007-08 heating season, Questar Gas had an estimated design-day demand of 1,163 MMdth.

Questar Gas has long-term contracts with Questar Pipeline for transportation and storage capacity at Clay Basin and three peak-day storage facilities. Questar Gas also has contracts to take deliveries at several locations on the Kern River Pipeline.

Competition, Customers and Growth: Questar Gas currently does not face direct competition from other distributors of natural gas for residential and commercial customers in its service territory. Natural gas has historically enjoyed a favorable price comparison with other energy sources used by residential and commercial customers with the notable exceptions of electricity from coal-fired power plants and occasionally fuel oil when oil prices are low. Questar Gas provides transportation service to industrial customers who buy gas directly from other suppliers. Questar Gas earns lower margins on this transportation service than firm-sales service and faces the risk that it could lose customers to competitor, Kern River Pipeline.

Regulation: As a public utility, Questar Gas is subject to the jurisdiction of the PSCU and PSCW. Natural gas sales and transportation services are provided under rate schedules approved by the two regulatory commissions. Questar Gas is authorized to earn a return on equity of 11.2% in Utah and 11.83% in Wyoming. Both the PSCU and PSCW permit Questar Gas to recover gas costs through a balancing-account procedure and to reflect natural gas-price changes on a periodic basis, typically twice a year in the spring and the fall. Questar Gas has also received permission from the PSCU and PCSW to recover as part of its gas costs the specific costs associated with derivative contracts.

Questar Gas has significant relationships with affiliates that have allowed it to lower its costs and improve efficiency. Transactions between Questar Gas and its affiliates are subject to greater scrutiny by regulators.

Questar Gas is subject to the requirements of the Pipeline Safety Improvement Act. Questar Gas estimates that it will cost $4.0 to $5.0 million per year to comply with the Act, not including costs of pipeline replacement if necessary. The PSCU has allowed Questar Gas to recover $2.0 million per year of these costs beginning June 2006 and to record a regulatory asset for additional incremental operating costs incurred to comply with this Act.

Corporate

Questar’s Corporate provides legal, finance, human resources, audit and insurance services for its subsidiaries.

Environmental Matters

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

Employees

At December 31, 2007, the Company had 2,324 employees, including 775 in Market Resources, 283 in Questar Pipeline, 1,198 in Questar Gas and 68 in Corporate.

Executive Officers

The following individuals are serving as executive officers of the Company:

Primary Positions Held with the Company

and Affiliates, Other Business Experience

Keith O. Rattie

54

Chairman (2003); President (2001); Chief Executive Officer (2002); Director (2001); Chief Operating Officer (2001 to 2002); Director, Questar affiliates (2001). Prior to coming to Questar, Mr. Rattie served successively as Vice President and Senior Vice President of the Coastal Corporation (1996 to 2001).

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Charles B. Stanley

49

Chief Operating Officer, Questar (2008); Executive Vice President and Director, Questar (2002); President, Chief Executive Officer and Director, Market Resources and Market Resources subsidiaries (2002); Senior Vice President, Questar (2002 to 2002); Executive Vice President and Chief Operating Officer, Market Resources and Market Resources subsidiaries (2002 to 2002). Prior to joining Questar, Mr. Stanley was President, Chief Executive Officer and Director, Coastal Gas International Co. (1995 to 2000); President and Chief Executive Officer, El Paso Oil and Gas Canada, Inc. (2000 to January 2002).

Alan K. Allred

57

Executive Vice President, Questar (2003); President and Chief Executive Officer and Director, Questar Regulated Services (2003 to 2006) and Questar Gas (2003); Chief Executive Officer and Director, Questar Pipeline (2003 to 2006); President, Questar Pipeline (2003 to 2005); Executive Vice President and Chief Operating Officer, Questar Regulated Services, Questar Gas and Questar Pipeline (2002 to 2003); Senior Vice President, Questar Regulated Services, Questar Gas and Questar Pipeline (2002 to 2002); Vice President, Business Development, Questar Regulated Services, Questar Gas and Questar Pipeline (2000 to 2002); Manager, Regulatory Affairs, Questar Gas and Questar Pipeline (1997 to 2000). Mr. Allred plans to retire in 2008.

R. Allan Bradley

56

Senior Vice President, Questar (2005); Chief Executive Officer, Questar Pipeline (2006); President, Chief Operating Officer and Director, Questar Pipeline (2005); Prior to joining Questar, Mr. Bradley was Managing Director and founding member, Ventura Energy LLC (2002 to 2004) and Senior Vice President, Coastal Corporation and El Paso Corporation affiliates (1990 to 2002).

Stephen E. Parks

56

Senior Vice President and Chief Financial Officer (2001); Chief Financial Officer (1996); Treasurer (1984 to 2004); Vice President (1990 to 2001); Vice President and Chief Financial Officer of all affiliates (at various dates beginning 1984); and Director Market Resources subsidiaries (at various dates beginning in 1996).

Thomas C. Jepperson

53

Vice President and General Counsel, Questar (2005); Division Counsel (2000 to 2004) Managing Attorney (1990 to 1999) and Senior Attorney (1988 to 1989) for Market Resources.

Abigail L. Jones

47

Vice President Compliance (2007) and Corporate Secretary (2005); Assistant Secretary (2004 to 2005); Senior Attorney (2002 to 2005) for Questar Regulated Services and for the Company (2005 to 2007).

There is no “family relationship” between any of the listed officers or between any of them and the Company’s directors. The executive officers serve at the pleasure of the Board of Directors. There is no arrangement or understanding under which the officers were selected.

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 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;

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•

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 in volves 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 operat ions.

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 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.

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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.

Questar is dependent on bank credit facilities and continued access to capital markets to successfully execute its operating strategies. Questar 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 Questar’s 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 Questar 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. Manageme nt 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

A significant portion of Market Resources production, revenue and cash flow is derived from assets that are concentrated in the 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.

Questar uses derivative arrangements to manage exposure to uncertain prices. Questar 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. Questar believes its regulated businesses – interstate natural gas transportation and retail gas distribution – and its Wexpro subsidiary generate revenues that are not significantly sensitive to short-term fluctuations in commodity prices.

Questar 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 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

Questar 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.

Questar 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.

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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.

Both Questar Pipeline and Questar Gas incur significant costs to comply with federal pipeline-safety regulations.

Questar 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. Questar’s 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 Questar operates are considering various greenhouse gas registration and reduction programs. Carbon dioxide regulation could increase t he 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 Questar’s business, operations or financial results.

FERC regulates interstate transportation of natural gas. Questar Pipeline’s natural gas transportation and storage operations are regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The FERC has authority to: set rates for natural gas transportation, storage and related services; set rules governing business relationships between the pipeline subsidiary and its affiliates; approve new pipeline and storage-facility construction; and establish policies and procedures for accounting, purchase, sale, abandonment and other activities. FERC policies may adversely affect Questar Pipeline profitability. The FERC also has various affiliate rules that may cause the Company to incur additional costs of compliance.

State agencies regulate the distribution of natural gas. Questar Gas natural gas-distribution business is regulated by the PSCU and the PSCW. These commissions set rates for distribution services and establish policies and procedures for services, accounting, purchase, sale and other activities. PSCU and PSCW policies may adversely affect Questar Gas profitability.

Other Risks

General economic and other conditions impact Questar’s results. Questar’s 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 bodies; terrorist attacks or acts of war; changes in business or financial condition; changes in credit ratings; and availability of financing for Questar.

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.

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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.

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

In addition to this filing, Questar E&P and Wexpro will each file 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.

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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.

	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 are convertible to working interests after recovery of certain costs by third parties. After converting to working interests, these overriding-royalty interests will be included in the gross and net-well count.

Leasehold Acres

The following table summarizes developed and undeveloped-leasehold acreage in which the Company owns a working interest as of December 31, 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

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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
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. Leases held by production remain in effect until production ceases. The following table sets forth the gross and net acres subject to leases summarized in the preceding table that will expire during the periods indicated:

Leaseholds Expiring	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.

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	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 Pipeline’s Muddy Creek compressor station that can deliver up to 300 MMcf of natural gas per day to markets in California and Nevada served by the Kern River Pipeline. In conjunction with these gathering facilities, Gas Management owns compression facilities, field-dehydration and measuring systems. Rendezvous owns an additional 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.

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.

Interstate Gas Transportation – Questar Pipeline

Questar Pipeline has a maximum capacity of 4,006 Mdth per day and firm-capacity commitments of 3,112 Mdth per day. Questar Pipeline’s transmission system includes 2,505 miles of transmission lines that interconnect with other pipelines. Its core system includes two segments, referred to as the northern system and southern system. The northern system extends from northwestern Colorado through southwestern Wyoming into northern Utah, while the southern system extends from western Colorado to Goshen, Utah. The transmission mileage includes lines at storage fields and tap lines used to serve Questar Gas, the 488 miles of the Southern Trails system in service that is owned by a subsidiary, and the 137 miles of Overthrust Pipeline that is owned by a subsidiary. The maximum-daily capacity included above for Southern Trails is 85 Mdth and Overthrust is 1,423 Mdth. Questar Pipeline’s system ranges in size from lines that are less than four inches in diameter to the Overthrust line that is 36 inches in diameter. Southern Trails also owns 161 miles of pipeline comprising the California segment of the Southern Trails system. This segment has not been placed in service. Questar Pipeline also owns large-scale compressor stations, which boost the pressure of natural gas transported on its pipelines for delivery to utility customers and third-party pipelines.

Questar Pipeline also owns the Clay Basin storage facility in northeastern Utah, which has a certificated capacity of 117.5 Bcf, including 51.3 Bcf of working gas. Questar Pipeline also owns three smaller storage aquifers in northeastern Utah and western Wyoming. Through a subsidiary, Questar Pipeline owns processing plants near Price, Utah, and related gathering lines.

Retail Gas Distribution - Questar Gas

Questar Gas distributes gas to customers in the major populated area of Utah, commonly referred to as the Wasatch Front, including the metropolitan Salt Lake area, Provo, Park City, Ogden, and Logan. It also serves customers throughout the state, including the cities of Price, Roosevelt, Vernal, Moab, Monticello, Fillmore, Cedar City and St. George. Questar Gas supplies natural gas to the southwestern Wyoming communities of Rock Springs, Green River, Evanston, Kemmerer and Diamondville and the southeastern Idaho community of Preston. To supply these communities Questar Gas owns and operates distribution systems and has a total of 25,373 miles of street mains, service lines and interconnecting pipelines. Questar Gas has a major operations center in Salt Lake City, and has operations centers, field offices and service-center facilities through other parts of its service area.

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ITEM 3.  LEGAL PROCEEDINGS.

Questar 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 violatio ns 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.

Regulatory Proceedings

See Note 7 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for information concerning various regulatory proceedings.

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

The Company did not submit any matters to a vote of stockholders during the last quarter of 2007.

PART II

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

5-Year Cumulative Total Return to Shareholders

The following graph compares the cumulative total return of the company’s common stock with the cumulative total returns of an industry group of six diversified natural gas companies selected by Questar, and of the S&P 500 Composite Stock Price Index.

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	2002	2003	2004	2005	2006	2007
Questar	$100	$130	$192	$289	$321	$422
Industry Group	100	133	183	249	301	388
S&P 500	100	129	143	150	173	183

The chart assumes $100 is invested at the close of trading on December 31, 2002 in the Company’s common stock, the indices of six peer companies, and the S&P 500 Index. It also assumes all dividends are reinvested. For 2007, the Company had a total return of 31.6% compared to 5.4% for the S&P 500 Index and 29.1% for the six-company peer group. For the five-year period, the Company had a compound annual total return of 33.4% compared to 12.8% for the S&P 500 Index and 31.2% for the peer group. The peer group index is comprised of Energen Corporation, Equitable Resources, Inc., MDU Resources, National Fuel Gas Company, Oneok Inc. and Southwestern Energy Company. MDU Resources replaced Kinder Morgan Inc. in 2007 because Kinder Morgan Inc. ceased to be a publicly-traded company.

Information concerning the market for the common equity of the Company and the dividends paid on such stock is located in Note 15 to the consolidated financial statements included in Item 8 of Part II of this Annual Report. As of January 31, 2008, Questar had 9,253 shareholders of record.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

The following table sets forth the Company’s purchases of common stock registered under Section 12 of the Exchange Act that occurred during the quarter ended December 31, 2007.

2007	Number of Shares Purchased(a)	Average Price per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares that May Yet Be Purchased Under the Plans
October	13,823	$55.17	-	-
November	33,997	55.61	-	-
December	6,208	54.64	-	-
Total	54,028	$55.38	-	-

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^(a)The numbers include any shares purchased in conjunction with tax-payment elections under the Company’s Long-term Stock Incentive Plan and rollover shares used in exercising stock options. They exclude any fractional shares purchased from terminating participants in Questar’s Dividend Reinvestment and Stock Purchase Plan and any shares of restricted stock forfeited when failing to satisfy vesting conditions.

ITEM 6.  SELECTED FINANCIAL DATA.

	Year Ended December 31,
	2007	2006	2005	2004	2003
	(in millions, except per-share amounts)
Revenues	$2,726.6	$2,835.6	$2,724.9	$1,901.4	$1,463.2
Operating expenses
Cost of natural gas and other products sold	917.1	1,223.6	1,371.3	821.8	527.4
Operating and maintenance	298.6	286.8	262.8	213.6	205.0
General and administrative	165.4	135.0	123.1	114.2	94.3
Production and other taxes	101.0	108.7	120.2	90.9	70.7
Depreciation, depletion and amortization	369.1	308.4	250.3	216.2	192.4
Other expenses	33.2	42.0	35.4	29.1	33.6
Total operating expenses	1,884.4	2,104.5	2,163.1	1,485.8	1,123.4
Net gain (loss) from asset sales	(0.9)	25.3	4.7	0.3	(0.3)
Operating income	841.3	756.4	566.5	415.9	339.5
Interest and other income	20.0	9.3	9.0	6.3	8.0
Income from unconsolidated affiliates	8.9	7.5	7.5	5.1	5.0
Interest expense	(72.2)	(73.6)	(69.4)	(68.4)	(70.7)
Income taxes	(290.6)	(255.5)	(187.9)	(129.6)	(102.6)
Income before accounting change	507.4	444.1	325.7	229.3	179.2
Cumulative effect of accounting change					(5.6)
Net income	$  507.4	$  444.1	$  325.7	$  229.3	$  173.6
Basic earnings per common share
Income before accounting change	$2.95	$2.60	$1.92	$1.37	$1.09
Cumulative effect of accounting change					(0.04)
Net income	$2.95	$2.60	$1.92	$1.37	$1.05
Diluted earnings per common share
Income before accounting change	$2.88	$2.54	$1.87	$1.34	$1.07
Cumulative effect of accounting change					(0.04)
Net income	$2.88	$2.54	$1.87	$1.34	$1.03
Weighted-average common shares outstanding
Used in basic calculation	172.0	170.9	169.6	167.5	165.4
Used in diluted calculation	175.9	175.2	174.3	171.4	168.4
Dividends per share	$0.485	$0.465	$0.445	$0.425	$0.39
Book value per common share at December 31,	$14.92	$12.83	$  9.08	$  8.53	$  7.58
Net cash provided from operating activities	$1,141.0	$   965.0	$   695.8	$   585.7	$   436.6
Capital expenditures	1,398.3	916.1	712.7	446.5	325.6
Total assets at December 31,	$5,944.2	$5,064.7	$4,374.3	$3,684.9	$3,337.4

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Capitalization at December 31,
Long-term debt, less current portion	$1,021.2	$1,022.4	$  983.2	$   933.2	$   950.2
Common equity	2,577.9	2,205.5	1,549.8	1,439.6	1,261.3
Total capitalization	$3,599.1	$3,227.9	$2,533.0	$2,372.8	$2,211.5

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

RESULTS OF OPERATION

	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
Market Resources total	420.8	356.1	258.2	64.7	97.9
Interstate Gas Transportation – Questar Pipeline	45.0	45.4	26.6	(0.4)	18.8
Retail Gas Distribution – Questar Gas	37.4	37.0	36.0	0.4	1.0
Corporate	4.2	5.6	4.9	(1.4)	0.7
Net income	$507.4	$444.1	$325.7	$63.3	$118.4
Earnings per share – diluted	$  2.88	$ 2.54	$ 1.87	$0.34	$ 0.67

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
Natural gas purchases	2.2	2.8	4.2
Total operating expenses	482.8	404.8	322.1

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Net 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 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:

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	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 pric es before the impact of hedges.

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.

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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 in 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.

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.

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.

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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.

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.

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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.

Interstate Gas Transmission – Questar Pipeline

Questar Pipeline reported 2007 net income of $45.0 million compared with $45.4 million in 2006, a 1% decrease. Operating income was 4% lower in 2007 compared to the 2006 due primarily to increased expenses related to a system expansion and lower NGL sales. The company began collecting revenues from the Overthrust Pipeline Opal expansion in 2006 at an interim delivery point on the Kern River Pipeline before completion of the new facilities in January 2007. In 2007, Questar Pipeline incurred higher operating and depreciation expenses after placing the new facilities in service. Following is a summary of Questar Pipeline financial and operating results:

	Year Ended December 31,
	2007	2006	2005
	(in millions)
OPERATING INCOME
Revenues
Transportation	$127.4	$119.9	$108.2
Storage	37.6	37.6	37.4
Gas processing	8.7	6.3	5.6
NGL sales	8.5	11.0	9.2
Energy services	16.0	16.1	12.7
Other	7.7	6.6	11.2
Total revenues	205.9	197.5	184.3
Operating expenses
Operating and maintenance	37.7	33.4	30.7
General and administrative	31.3	25.3	34.2
Depreciation and amortization	35.0	32.3	30.5
Cost of goods sold	4.0	4.8	5.4
Impairment of the California segment of Southern Trails Pipeline			16.0
Other taxes	7.3	7.3	6.3
Operating expenses	115.3	103.1	123.1
Net gain from asset sales	0.4	0.4	3.8
Operating income	$ 91.0	$ 94.8	$ 65.0
OPERATING STATISTICS
Natural gas-transportation volumes (MMdth)
For unaffiliated customers	352.3	320.4	259.3
For Questar Gas	113.8	116.7	116.3
For other affiliated customers	16.0	26.3	25.7
Total transportation	482.1	463.4	401.3
Transportation revenue (per dth)	$0.26	$0.26	$0.27
Firm daily transportation demand at December 31, (Mdth)	3,112	2,152	1,920
Natural gas processing
NGL sales (MMgal)	7.2	9.0	6.7
NGL sales price (per gal)	$1.19	$1.22	$1.36

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Revenues

Following is a summary of major changes in Questar Pipeline revenues for 2007 compared with 2006 and 2006 compared with 2005:

	Change in Revenues
	2007 to 2006	2005 to 2006
	(in millions)
Transportation
New transportation contracts	$9.4	$14.4
Expiration of transportation contracts	(1.7)	(2.7)
Other	(0.2)
Storage		0.2
Gas processing	2.4	0.7
NGL sales
Change in NGL prices and volumes	(2.5)	4.2
Adjustment to credit of NGL revenues in 2005		(2.4)
Energy services	(0.1)	3.4
Other	1.1	(4.6)
Increase	$8.4	$13.2

As of December 31, 2007, Questar Pipeline had firm-transportation contracts of 3,112 Mdth per day compared with 2,152 Mdth per day as of December 31, 2006. Questar Pipeline has expanded its transportation system in response to growing regional natural gas production and transportation demand. On January 1, 2007, Questar Pipeline began operations on an expansion of the Overthrust Pipeline to a connection with Kern River Pipeline at Opal, Wyoming. The majority of the contracts for this expansion were effective at the beginning of 2006 at an interim delivery point pending construction and startup of the new facilities. Questar Pipeline completed an expansion of its southern system and placed the pipeline in service on November 1, 2007. Additional long-term firm contracts from this expansion totaled 175 Mdth per day. The Company completed its expansion of Overthrust Pipeline to Wamsutter and began interruptible transportation services on this pipeline in mid-December 2007. A long-term capac ity lease and additional firm contracts from this expansion totaled 750 Mdth per day.

Questar Pipeline has increased transportation revenues by remarketing expiring contracts with discounted rates ranging from $0.08 per dth to $0.12 per dth into maximum rate contracts ($0.17 per dth) for terms of up to 31 years and, where possible, has restructured single contracts into multiple contracts.

Questar Gas is Questar Pipeline’s largest transportation customer with contracts for 901 Mdth per day. The majority of Questar Gas transportation contracts extend through mid-2017.

Questar Pipeline owns and operates the Clay Basin underground storage complex in eastern Utah. This facility is 100% subscribed under long-term contracts. In addition to Clay Basin, Questar Pipeline also owns and operates three smaller aquifer gas storage facilities. Questar Gas has contracted for 26% of firm-storage capacity at Clay Basin for terms extending from five to 11 years and 100% of the firm-storage capacity at the aquifer facilities for terms extending for 10 years.

Questar Pipeline charges FERC-approved transportation and storage rates that are based on straight fixed-variable rate design. Under this rate design, all fixed costs of providing service including depreciation and return on investment are recovered through the demand charge. About 95% of Questar Pipeline costs are fixed and recovered through these demand charges. Questar Pipeline’s revenues and earnings are driven primarily by demand charges from firm shippers. Since only about 5% of operating costs are recovered through volumetric charges, changes in transportation volumes do not have a significant impact on earnings, except when volume changes result from a change in contract demand.

Questar Pipeline NGL sales decreased 23% in 2007 compared to 2006 due to 20% lower volumes and lower realized prices due to lower quality liquids removed from the gas stream. In 2005 revenues were increased by a $2.4 million adjustment due to a resolution of a liquid-sharing arrangement in a fuel-gas reimbursement proceeding. During the third quarter of 2005, Questar Pipeline received approval of a settlement with customers that resolved outstanding issues in the 2004 and 2005 fuel gas reimbursement percentage (FGRP) filings. Included in this settlement was a resolution of the amount of liquid revenues at the Kastler plant to be retained by Questar Pipeline. Questar Pipeline recorded the impact of the settlement in third quarter 2005 increasing liquid revenues by $2.4 million and net income by $1.5 million.

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Questar Pipeline’s subsidiary, Questar InfoComm, provides well-head automation and measurement services to natural gas producers in the Rockies. Questar InfoComm previously provided data-hosting services. Well-head automation and measurement services revenues were slightly lower in 2007 as higher service revenues were offset by lower wellhead automation equipment sales. Well-head automation and measurement revenues increased $3.4 million in 2006.

Expenses

Operating, maintenance, general and administrative expenses increased by 18% to $69.0 million in 2007 compared to $58.7 million in 2006 and $64.9 million in 2005. Higher operating costs were primarily related to pipeline system expansions and gas processing. Operating, maintenance, general and administrative expenses per dth transported were $0.14 in 2007 compared with $0.13 in 2006 and $0.16 in 2005. Operating, maintenance, general and administrative expenses include processing and storage costs.

Depreciation expense increased 8% in 2007 compared to 2006 and increased 6% in 2006 compared to 2005 due to investment in pipeline expansions.

Clay Basin Storage

In 2002, the company noted a discrepancy between the book volume of cushion gas at Clay Basin and the volume implied by reservoir pressure-test data. Reservoir modeling and pressure tests over the last five years have verified the integrity of the reservoir. The company believes that an estimated 3.2 Bcf of cushion gas may have been lost in the course of normal operations over the past 30 years. This loss represents 0.25% of the volume of gas cycled into and out of the reservoir since storage operations began in 1977. During 2007, Questar Pipeline added to the volume of cushion gas in the Clay Basin reservoir by purchasing and injecting 2.8 Bcf of gas at a cost of $5.5 million. Questar Pipeline plans to purchase an additional 0.4 Bcf during 2008 to replace the remainder of the estimated 3.2 Bcf cushion-gas shortfall. This will restore the volume of cushion gas in the Clay Basin reservoir to the FERC-certificated level.

Southern Trails Pipeline

See Note 4 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for discussion of the impairment of the California segment of Southern Trails and potential impairment of the eastern segment.

Salt Cavern Storage Project

Questar Pipeline has invested $11.5 million in a salt cavern storage project in southwest Wyoming. The project is on hold pending updated feasibility studies and customer commitments. Several third parties are funding the updated feasibility studies in exchange for the right to participate in the project.

Retail Gas Distribution – Questar Gas

Questar Gas, which provides natural gas distribution services in Utah, Wyoming and Idaho, reported net income of $37.4 million for 2007 compared with $37.0 million in 2006, a 1% increase, and $36.0 million in 2005. Operating income increased $1.2 million, or 2%, in the 2007 to 2006 comparison due primarily to higher margins from customer growth and lower bad debt and depreciation expenses. Following is a summary of Questar Gas’s financial and operating results:

	Year Ended December 31,
	2007	2006	2005
	(in millions)
OPERATING INCOME
Revenues
Residential and commercial sales	$876.6	$ 988.4	$867.8
Industrial sales	9.9	23.5	40.1
Transportation for industrial customers	9.9	6.7	5.9
Service	5.9	7.1	6.6
Other	30.2	38.9	42.1
Total revenues	932.5	1,064.6	962.5
Cost of natural gas sold	687.2	821.8	720.2
Margin	245.3	242.8	242.3
Operating expenses
Operating and maintenance	73.4	73.2	73.7
General and administrative	45.5	41.9	39.3

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Depreciation and amortization	38.8	40.9	45.8
Other taxes	11.5	11.6	11.0
Total operating expenses	169.2	167.6	169.8
Net (loss) from asset sales		(0.3)
Operating income	$   76.1	$   74.9	$  72.5
OPERATING STATISTICS
Natural gas volumes (MMdth)
Residential and commercial sales	106.1	102.2	96.3
Industrial sales	1.6	3.1	5.7
Transportation for industrial customers	53.8	35.5	31.2
Total industrial	55.4	38.6	36.9
Total deliveries	161.5	140.8	133.2
Natural gas revenue (per dth)
Residential and commercial	$8.26	$9.67	$9.01
Industrial sales	6.18	7.64	7.06
Transportation for industrial customers	0.18	0.19	0.19
System natural gas cost (per dth)	$ 5.93	$ 6.54	$6.46
Temperatures – colder (warmer) than normal	2%	(2%)	(3%)
Temperature-adjusted usage per customer (dth)	110.8	113.6	113.3
Customers at December 31, (in thousands)	873.6	850.5	824.4

Margin Analysis

Questar Gas’s margin (revenues less gas costs) increased $2.5 million in 2007 compared to 2006, and $0.5 million in 2006 compared with 2005. Following is a summary of major changes in Questar Gas’s margin for 2007 compared to 2006 and 2006 compared to 2005:

	Change in Margin
	2006 to 2007	2005 to 2006
	(in millions)
New customers	$  5.9	$  6.9
Conservation-enabling tariff	4.3	(1.7)
Change in usage per customer	(4.2)	0.5
Change in transportation revenues	3.2	0.6
Change in rates	(6.2)	(4.9)
Recovery of demand-side management costs	0.6
Recovery of gas-cost portion of bad-debt costs	(2.1)	(2.8)
Other, including shifting between rate classes	1.0	1.9
Increase	$  2.5	$  0.5

At December 31, 2007, Questar Gas served 873,607 customers, up from 850,542 at December 31, 2006. Customer growth increased margin by $5.9 million in 2007 and $6.9 million in 2006.

Temperature-adjusted usage-per-customer decreased 2% in 2007 compared to 2006 and decreased less than 1% in 2006 compared to 2005. The impact on the company’s margin from changes in usage-per-customer has been mitigated by a pilot conservation-enabling tariff that was approved by the PSCU in October 2006, effective back to the beginning of 2006. The new tariff resulted in a margin increase of $2.5 million in 2007, largely offsetting a $4.2 million decline in usage-per-customer.

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Effective June 1, 2006, the company reduced gas rates for Utah customers by $9.7 million per year, primarily to reflect depreciation rates and corresponding reduction in the company’s depreciation expense. As a result, Questar Gas realized a $6.2 million reduction in revenues in 2007 compared to 2006. The lower depreciation rates reduced depreciation expense approximately $3.8 million in 2007 compared to the prior year.

See Note 7 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of the rate changes.

Weather, as measured in degree days, was 2% colder than normal in 2007 compared with 2% warmer than normal in 2006. A weather-normalization adjustment on customer bills generally offsets the revenue impacts of moderate temperature variations.

Industrial deliveries (including sales and transportation) increased 44% in 2007 compared to 2006 due to service to an electric generating plant. Industrial deliveries increased 5% in 2006 compared with 2005.

Revenues

Questar Gas reported revenues of $932.5 million in 2007 compared with $1,064.6 million in 2006. The decrease resulted from lower regional gas supply prices for natural gas included in rates. Questar Gas is permitted to collect gas costs, without markup, through rates.

Expenses

Cost of natural gas sold decreased 16% in 2007 compared to 2006 primarily due to lower gas-purchase expenses per dth. Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the PSCU and the PSCW. Purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. As of December 31, 2007, Questar Gas had a $58.1 million over-collected balance in the purchased-gas adjustment account representing costs recovered from customers in excess of costs incurred.

The sum of operating, maintenance, general and administrative expenses increased 3% in 2007 compared to 2006. Higher labor and benefit costs were offset by lower bad-debt costs. Operating, maintenance, general and administrative expenses per customer were $136 in 2007 compared to $135 in 2006 and $137 in 2005.

Depreciation expense decreased 5% in 2007 compared to 2006 and 11% in 2006 compared to 2005 primarily as a result of reduced depreciation rates effective June 1, 2006, in accordance with the PSCU order discussed above.

Utility Rate Matters

See Note 7 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of the Conservation Enabling Tariff, a rate reduction in Utah, and filing of a general rate case in Utah. Questar Gas is subject to the requirements of the Pipeline Safety Improvement Act. Questar Gas has been spending $4.0 to $5.0 million per year to comply with the act, not including costs of pipeline replacement if necessary. The PSCU has allowed Questar Gas to recover $2.0 million per year of these costs beginning June 2006 and to record a regulatory asset for additional incremental operating costs incurred to comply with this Act.

Consolidated Results Before Net Income

Interest and Other Income

The details of interest and other income for 2007, 2006 and 2005 are shown in the table below:

	Year Ended December 31,			Change	Change
	2007	2006	2005	2007 vs. 2006	2006 vs. 2005
	(in millions)
Interest income and other earnings	$ 6.8	$ 6.0	$3.3	$0.8	$2.7
Allowance for other funds used during
construction (capitalized finance costs)	2.0	1.0	0.7	1.0	0.3
Return earned on working-gas inventory
and purchased-gas-adjustment account	5.5	5.9	5.0	(0.4)	0.9
Total	$14.3	$12.9	$9.0	$1.4	$3.9

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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

Interest expense declined 2% in 2007 compared to 2006. Capitalized interest charges on pipeline construction amounted to $7.3 million in 2007 compared to $0.4 million in 2006. Interest expense rose in 2006 compared to 2005 due primarily to increased average debt levels during and higher interest rates on short-term debt outstanding in the early part of 2006.

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.

Income taxes

The effective combined federal and state income tax rate was 36.4% in 2007, 36.5% in 2006 and 36.6% in 2005.

LIQUIDITY AND CAPITAL RESOURCES

Operating Activities

Net cash provided from operating activities increased 18% in 2007 compared to 2006 and 39% in 2006 compared to 2005 due to higher net income and noncash adjustments to net income. Noncash adjustments to net income consist primarily of depreciation, depletion and amortization, and deferred income taxes. Cash sources from operating assets and liabilities were lower in 2007 primarily due to lower purchased-gas adjustments. Net cash provided from operating activities is presented below:

	Year Ended December 31,			Change	Change
	2007	2006	2005	2007 vs. 2006	2006 vs. 2005
	(in millions)
Net income	$507.4	$444.1	$325.7	$  63.3	$118.4
Noncash adjustments to net income	600.1	438.3	378.7	161.8	59.6
Changes in operating assets and liabilities	33.5	82.6	(8.6)	(49.1)	91.2
Net cash provided from operating activities	$1,141.0	$965.0	$695.8	$176.0	$269.2

Investing Activities

Capital spending in 2007 amounted $1,398.3 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)
Market Resources
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
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

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General	7.8	11.1	5.6
Capital expenditure accruals		(20.4)	(35.7)
	2,041.5	943.9	752.7
Questar Pipeline
Transportation system	50.4	111.5	13.5
Overthrust Pipeline	5.6	189.6	58.3
Southern Trails Pipeline	0.6	1.7	0.1
Storage	23.9	14.7	2.5
Gathering and processing	8.7	1.4	3.4
General	10.5	2.8	2.0
Capital expenditure accruals		(3.2)	(3.7)
	99.7	318.5	76.1
Questar Gas
Retail distribution system and customer additions	118.2	123.3	84.5
General	18.2	6.6	12.7
Capital expenditure accruals		6.0	(10.5)
	136.4	135.9	86.7
Corporate	0.1	0.1	0.6
Capital expenditure accruals		(0.1)
Total capital expenditures	$2,277.7	$1,398.3	$916.1

Market Resources

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.

Questar Pipeline

During 2007, Questar Pipeline completed construction of a 54-mile, 24-inch pipeline extending from the eastern terminus of the company’s Main Line 104 pipeline to the Green River block valve in south-central Utah. Also, a Questar Pipeline subsidiary completed an 80-mile extension of the Overthrust Pipeline from the eastern terminus of its transportation system at Kanda in Sweetwater County, Wyoming to an interconnect with the Rockies Express Pipeline LLC near Wamsutter in Sweetwater County, Wyoming.

Questar Gas

During 2007, Questar Gas added 646 miles of main, feeder and service lines to provide service to 23,065 additional customers.

Financing Activities

Net cash used in investing activities plus dividends paid exceeded net cash provided from operating activities by $327.8 million in 2007. As a result the Company increased short-term debt and long-term debt. Questar Gas has $43.0 million of notes maturing in the next 12 months. In January 2008, Questar Pipeline issued $200 million of 5.83% notes due 2018 to repay maturing debt and finance capital expenditures. Questar Gas intends to issue up to $150 million of long-term debt in 2008 to repay maturing debt and finance capital expenditures.

Short-term debt amounted to $260.6 million at December 31, 2007, and was comprised of commercial paper with an average interest rate of 5.7%. A year earlier short-term debt amounted to $40.0 million and was comprised of commercial paper with an average interest rate of 5.4%. Questar’s commercial paper borrowings are backed by short-term line-of-credit arrangements. At December 31, 2007, the Company had $380.0 million of short-term lines of credit available and Market Resources had a $182.0 million long-term revolving-credit facility with banks. 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.

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Questar’s consolidated capital structure consisted of 35% combined short- and long-term debt and 65% common shareholders’ equity at December 31, 2007, compared to 33% combined short- and long-term debt and 67% common shareholders’ equity a year earlier. Ratings of senior-unsecured debt as of December 31, 2007, were as shown below.

	Moody’s	Standard & Poor’s
Market Resources	Baa3	BBB+
Questar Pipeline	A2	A-
Questar Gas	A2	A-
Questar – short-term debt	P2	A2

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, Questar 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	$1,123.5	$101.3	$42.0	$50.0	$332.0	$191.5	$406.7
Interest on fixed-rate long-term debt	321.8	59.9	56.1	53.6	38.7	28.1	85.4
Gas-purchase contracts	659.2	197.6	85.5	50.4	32.4	27.8	265.5
Transportation contracts	109.0	13.0	12.9	12.9	12.6	10.7	46.9
Operating leases	30.1	6.5	6.5	6.3	5.8	3.7	1.3
Total	$2,243.6	$378.3	$203.0	$173.2	$421.5	$261.8	$805.8

The Company had $150 million of variable-rate long-term debt outstanding at December 31, 2007.

Critical Accounting Policies, Estimates and Assumptions

Questar’s 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 prove d reserves at December 31, 2007, and 25.9 Bcfe of additional cost-of-service proved reserves. See Note 16 for more information on the Company’s estimated proved reserves.

Successful Efforts Accounting for Gas and Oil Operations

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

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

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

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

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

Accounting for Derivative Contracts

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

Revenue Recognition

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

Questar Gas estimates revenues on a calendar basis even though bills are sent to customers on a cycle basis throughout the month.

The company estimates unbilled revenues for the period from the date meters are read to the end of the month, using usage history and weather information. Approximately one-half month of revenues is estimated in any period. The gas costs and other variable costs are recorded on the same basis to ensure proper matching of revenues and expenses.

Questar Gas tariff provides for monthly adjustments to customer bills to approximate the impact of normal temperatures on non-gas revenues. Questar Gas estimates the weather-normalization adjustment for the unbilled revenue each month. The weather-normalization adjustment is evaluated each month and reconciled on an annual basis in the summer to agree with the amount billed to customers. In 2006, the PSCU approved a pilot program for a conservation enabling tariff effective January 1, 2006, to promote energy conservation. Under the CET, Questar Gas non-gas revenues are decoupled from the volume of gas used by customers. The tariff specifies a margin per customer for each month with differences to be deferred and recovered from customers or refunded to customers through periodic rate adjustments. These adjustments are limited to five percent of non-gas revenues.

Rate Regulation

Regulatory agencies establish rates for the storage, transportation, distribution and sale of natural gas. The regulatory agencies also regulate, 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. Questar Gas and Questar Pipeline follow SFAS 71, “Accounting for the Effects of Certain Types of Regulation,” that requires the recording of regulatory assets and liabilities by companies subject to cost-based regulation. The FERC, PSCU and PSCW have accepted the recording of regulatory assets and liabilities.

Employee Benefit Plans

The Company has pension and postretirement-benefit plans covering a majority of its employees. The calculation of the Company’s expense and liability associated with its benefit plans requires the use of assumptions that the Company deems to be critical. Changes in these assumptions can result in different expenses and liabilities and actual experience can differ from these assumptions.

QUESTAR 2007 FORM 10-K

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Independent consultants hired by the Company use actuarial models to calculate estimates of pension and postretirement benefits expense. The models use key factors such as mortality estimations, liability discount rates, long-term rates of return on investments, rates of compensation increases, amortized gain or loss from investments and medical-cost trend rates. Management makes assumptions based on market indicators and advice from consultants. The Company believes that the liability discount rate and the expected long-term rate of return on benefit plan assets are critical assumptions.

The assumed liability discount rate reflects the current rate at which the pension benefit obligations could effectively be settled. Management considers the rates of return on high-quality, fixed-income investments and compares those results with a bond-defeasance technique. The Company discounted its future pension liabilities using rates of 6.50% as of December 31, 2007, and 5.75% as of December 31, 2006. A 0.5% increase in the discount rate would decrease the Company’s 2008 qualified-pension annual expense by about $3.2 million.

The expected long-term rate of return on benefit-plan assets reflects the average rate of earnings expected on funds invested or to be invested to provide for the benefits included in the benefit plan liability. The Company establishes the expected long-term rate of return at the beginning of each fiscal year giving consideration to the benefit plan’s investment mix and the historical and forecasted rates of return on these types of securities. The expected long-term rate of return determined by the Company was 8.00% as of January 1, 2007 and 2006. Benefit plan expense typically increases as the expected long-term rate of return on plan assets decreases. A 0.5% decrease in the expected long-term rate of return causes an approximate $1.7 million increase in the 2008 qualified pension expense.

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.

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

Commodity-Price Risk Management

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

QUESTAR 2007 FORM 10-K

38

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
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

QUESTAR 2007 FORM 10-K

39

				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 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.

Questar Gas had a fixed-price swap at December 31, 2006, that effectively fixed the purchase price of 3.0 Bcf of natural gas in the first quarter of 2007. The fair value of this fixed-price swap was a $7.6 million current liability at December 31, 2006, and is included in the tables below.

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

	Market Resources Fixed-Price Swaps	Market Resources Basis-Only Swaps	Questar Gas Fixed-Price Swaps	Total
	(in millions)
Net fair value of gas- and oil-derivative contracts   outstanding at December 31, 2006	$205.6	($1.9)	($7.6)	$196.1
Contracts realized or otherwise settled	(153.9)	(1.2)	7.6	(147.5)
Change in gas and oil prices on futures markets	(112.4)	(30.4)		(142.8)
Contracts added since December 31, 2006	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

QUESTAR 2007 FORM 10-K

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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	$196.1
Value if market prices of gas and oil and basis differentials decline by 10%	217.7	327.0
Value if market prices of gas and oil and basis differentials increase by 10%	(108.8)	65.2

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.

Questar Pipeline requests credit support, such as letters of credit and cash deposits, from those companies that pose unfavorable credit risks. All companies posing such concerns were current on their accounts at December 31, 2007. Questar Pipeline’s largest customers include Questar Gas, PacifiCorp, Anadarko, EOG Resources and Chevron/Texaco.

Questar Gas requires deposits from customers that pose unfavorable credit risks. No single customer accounted for a significant portion of revenue in 2007.

Interest-Rate Risk

The fair value of fixed-rate debt is subject to change as interest rates fluctuate. The Company had $1,123.5 million of fixed-rate long-term debt with a fair value of $1,139.1 million at December 31, 2007. A year earlier the Company had $1,033.5 million of fixed-rate long-term debt with a fair value of $1,065.2 million. If interest rates had declined 10%, fair value would increase to $1,164.4 million in 2007 and $1,094.4 million in 2006. The fair value calculations do not represent the cost to retire the debt securities.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Page No.

Financial Statements:

47

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

48

Consolidated Balance Sheets at December 31, 2007 and 2006

49

December 31, 2007

50

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

53

55

Financial Statement Schedules:

Valuation and Qualifying Accounts, for the three years ended December 31, 2007

85

All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of

Questar Corporation

We have audited the accompanying consolidated balance sheets of Questar Corporation as of December 31, 2007 and 2006, and the related consolidated statements of income, common shareholders’ 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as 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 Corporation 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 Corporation adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, effective January 1, 2007, Statement of Financial Accounting Standard No. 123R, Share Based Payments, effective January 1, 2006, and Statement of Financial Accounting Standard No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, effective December 31, 2006.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Questar Corporation’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2008 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Salt Lake City, Utah

February 22, 2008

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QUESTAR CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
	Year Ended December 31,
	2007		2006		2005
	(in millions, except per share amounts)
REVENUES
Market Resources	$1,671.3	$1,659.4		$1,668.7
Questar Pipeline	127.7	117.1		99.8
Questar Gas	927.6	1,059.1		956.4
Total Revenues	2,726.6	2,835.6		2,724.9
OPERATING EXPENSES
Cost of natural gas and other products sold (excluding operating     expenses shown separately)	917.1	1,223.6		1,371.3
Operating and maintenance	298.6	286.8		262.8
General and administrative	165.4	135.0		123.1
Production and other taxes	101.0	108.7		120.2
Depreciation, depletion and amortization	369.1	308.4		250.3
Impairment of California segment of Southern Trails Pipeline				16.0
Exploration	22.0	34.4		11.5
Abandonment and impairment	11.2	7.6		7.9
Total Operating Expenses	1,884.4	2,104.5		2,163.1
Net gain (loss) from asset sales	(0.9)	25.3		4.7
OPERATING INCOME	841.3	756.4		566.5
Interest and other income	14.3	12.9		9.0
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	(72.2)	(73.6)		(69.4)
INCOME BEFORE INCOME TAXES	798.0	699.6		513.6
Income taxes	290.6	255.5		187.9
NET INCOME	$   507.4	$   444.1		$  325.7
EARNINGS PER COMMON SHARE
Basic	$2.95	$2.60		$1.92
Diluted	2.88	$2.54		$1.87
Weighted average common shares outstanding
Used in basic calculation	172.0	170.9		169.6
Used in diluted calculation	175.9	175.2		174.3

See notes accompanying the consolidated financial statements

QUESTAR 2007 FORM 10-K

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QUESTAR CORPORATION
CONSOLIDATED BALANCE SHEETS
	December 31,
	2007	2006
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$      14.2	$     24.6
Federal income taxes recoverable	6.6	10.0
Accounts receivable, net	333.0	333.3
Unbilled gas accounts receivable	78.2	67.5
Fair value of derivative contracts	78.1	155.5
Inventories, at lower of average cost or market
Gas and oil storage	66.1	77.9
Materials and supplies	48.9	56.9
Prepaid expenses and other	33.8	32.0
Total Current Assets	658.9	757.7
Net Property, Plant and Equipment – successful
efforts method of accounting for gas and oil properties	5,098.6	4,091.4
Investment in Unconsolidated Affiliates	52.8	37.5
Other Assets
Goodwill	70.7	70.7
Regulatory assets	28.4	28.4
Fair value of derivative contracts	7.8	49.0
Other noncurrent assets, net	27.0	30.0
Total Other Assets	133.9	178.1
Total Assets	$5,944.2	$5,064.7

QUESTAR 2007 FORM 10-K

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QUESTAR CORPORATION
	December 31,
	2007	2006
	(in millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term debt	$   260.6	$     40.0
Accounts payable and accrued expenses
Accounts and other payables	463.1	438.9
Production and other taxes	52.1	68.9
Customer credit balances	34.1	31.4
Interest	15.2	14.9
Total accounts payable and accrued expenses	564.5	554.1
Fair value of derivative contracts	9.3	8.2
Purchased-gas adjustment	58.1	34.3
Deferred income taxes - current	4.9	35.0
Current portion of long-term debt	101.3	10.0
Total Current Liabilities	998.7	681.6
Long-term debt, less current portion	1,021.2	1,022.4
Deferred income taxes	942.4	763.9
Asset retirement obligations	149.1	132.4
Pension liability	73.3	106.0
Postretirement benefits liability	30.2	37.8
Fair value of derivative contracts	22.1	0.2
Other long-term liabilities	129.3	114.9
Commitments and contingencies – Note 11
COMMON SHAREHOLDERS’ EQUITY
Common stock – without par value; 350.0 shares authorized;
172.8 outstanding at December 31, 2007, and 171.8 outstanding at December 31, 2006	429.3	409.6
Retained earnings	2,173.9	1,750.2
Accumulated other comprehensive income (loss)	(25.3)	45.7
Total Common Shareholders’ Equity	2,577.9	2,205.5
Total Liabilities and Common Shareholders’ Equity	$5,944.2	$5,064.7

See notes accompanying the consolidated financial statements

QUESTAR 2007 FORM 10-K

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QUESTAR CORPORATION
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
						Accumulated
						Other
	Common Stock		Retained			Comprehensive	Comprehensive
	Shares	Amount	Earnings			Income (Loss)	Income (Loss)
	(in millions)
Balances at January 1, 2005	168.8	$358.0		$1,135.7	($54.2)
Common stock issued	2.2	16.9
Common stock repurchased	(0.4)	(9.7)
2005 net income				325.7				$325.7
Dividends paid ($0.445 per share)				(75.6)
Share-based compensation		4.2
Tax benefit from share-based compensation		13.9
Other comprehensive income
Change in unrealized fair value of derivatives					(251.5)			(251.5)
Minimum pension liability					(14.8)			(14.8)
Income taxes					101.2			101.2
Total comprehensive income								$160.6
Balances at December 31, 2005	170.6	383.3		1,385.8	(219.3)
Common stock issued	1.4	10.8
Common stock repurchased	(0.2)	(6.2)
2006 net income				444.1				$444.1
Dividends paid ($0.465 per share)				(79.7)
Share-based compensation		9.7
Tax benefit from share-based compensation		12.0
Other comprehensive income
Change in unrealized fair value of derivatives					524.9			524.9
Minimum pension liability					34.3
Change in unrecognized actuarial loss					(112.8)			(112.8)
Change in unrecognized prior-service costs					(20.5)			(20.5)
Income taxes					(160.9)			(160.9)
Total comprehensive income								$674.8
Balances at December 31, 2006	171.8	409.6		1,750.2	45.7
Common stock issued	1.2	5.9
Common stock repurchased	(0.2)	(10.2)
2007 net income				507.4				$507.4
Dividends paid ($0.485 per share)				(83.7)
Share-based compensation		12.9
Tax benefit from share-based compensation		11.1
Other comprehensive income
Change in unrealized fair value of derivatives					(156.1)			(156.1)
Change in unrecognized actuarial gain					39.1			39.1
Change in unrecognized prior-service costs					3.1			3.1
Income taxes					42.9			42.9
Total comprehensive income								$436.4
Balances at December 31, 2007	172.8	$429.3		$2,173.9	($25.3)

See notes accompanying the consolidated financial statements

QUESTAR 2007 FORM 10-K

46

QUESTAR CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Year Ended December 31,
	2007	2006	2005
	(in millions)
OPERATING ACTIVITIES
Net income	$   507.4	$   444.1	$  325.7
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	375.8	316.1	257.5
Deferred income taxes	191.2	100.7	92.2
Abandonment and impairment	11.2	7.6	7.9
Share-based compensation	12.9	9.7	4.2
Dry exploratory well expenses	12.3	26.3	3.1
Impairment of California segment of Southern Trails Pipeline			16.0
Net (gain) loss from asset sales	0.9	(25.3)	(4.7)
Income from unconsolidated affiliates	(8.9)	(7.5)	(7.5)
Distributions 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	(7.6)	61.8	(138.0)
Inventories	26.7	(8.0)	(40.0)
Prepaid expenses	3.3	2.4	(6.7)
Accounts payable and accrued expenses	(13.6)	(72.2)	182.7
Rate-refund obligation			(25.3)
Federal income taxes	3.4	1.3	0.4
Purchased-gas adjustments	16.2	81.7	(4.0)
Other	5.1	15.6	22.3
NET CASH PROVIDED FROM OPERATING ACTIVITIES	1,141.0	965.0	695.8
INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(1,383.5)	(909.8)	(712.7)
Other investments	(14.8)	(6.3)
Total capital expenditures	(1,398.3)	(916.1)	(712.7)
Cash used in disposition of assets	(9.6)	(1.3)	(1.1)
Proceeds from disposition of assets	22.8	35.9	19.6
NET CASH USED IN INVESTING ACTIVITIES	(1,385.1)	(881.5)	(694.2)
FINANCING ACTIVITIES
Common stock issued	5.9	10.8	16.9
Common stock repurchased	(10.2)	(6.2)	(9.7)
Long-term debt issued, net of issue costs	100.0	247.0	250.0
Long-term debt repaid	(10.0)	(200.0)	(200.0)
Early extinguishment of debt costs		(1.7)
Change in short-term debt	220.6	(54.5)	26.5

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Dividends paid	(83.7)	(79.7)	(75.6)
Excess tax benefits from share-based compensation	11.1	12.0
NET CASH PROVIDED FROM (USED IN) FINANCING ACTIVITIES	233.7	(72.3)	8.1
Change in cash and cash equivalents	(10.4)	11.2	9.7
Beginning cash and cash equivalents	24.6	13.4	3.7
Ending cash and cash equivalents	$    14.2	$   24.6	$   13.4
Supplemental Disclosure of Cash Paid During the Year for:
Interest	$    77.3	$   70.4	$   67.8
Income taxes	89.5	144.1	86.5

See notes accompanying the consolidated financial statements

QUESTAR CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies

Nature of Business

Questar Corporation (Questar or the Company) is a natural gas-focused energy company with five major lines of business – gas and oil exploration and production, midstream field services, energy marketing, interstate gas transportation, and retail gas distribution – which are conducted through its three principal subsidiaries:

·

Questar Market Resources, Inc. (Market Resources) is a subholding company that operates through 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. Questar Energy Trading Company (Energy Trading) markets equity and third-party natural gas and oil, provides risk-management services and owns and operates an underground gas-storage reservoir.

·

Questar Pipeline Company (Questar Pipeline) provides interstate natural gas transportation and storage and other energy services.

·

Questar Gas Company (Questar Gas) provides retail natural gas distribution services in Utah, Wyoming and Idaho.

Principles of Consolidation

The consolidated financial statements contain the accounts of Questar 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

Questar 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 the Company’s 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.

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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. Questar is primarily engaged in gas and oil exploration and production, midstream field services, interstate gas transportation and retail gas distribution. Energy Trading markets equity and third-party natural gas, oil and NGL volumes. Energy Trading uses derivatives to secure a known price for a specific volume over a specific time period. Energy Trading does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. Energy Trading has not engaged in buy/sell arrangements, as described in EITF 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty”.

The straight fixed-variable rate design used by Questar Pipeline, which allows for recovery of substantially all fixed costs in the demand or reservation charge, reduces the earnings impact of volume changes on gas-transportation and storage operations. Rate-regulated companies may collect revenues subject to possible refunds and establish reserves pending final orders from regulatory agencies.

Questar Gas records revenues for gas delivered to residential and commercial customers but not billed as of the end of the accounting period. Unbilled gas deliveries are estimated for the period from the date meters are read to the end of the month. Approximately one-half month of revenue is estimated in any period. Gas costs and other variable costs are recorded on the same basis to ensure proper matching of revenues and expenses. Questar Gas tariff allows for monthly adjustments to customer bills to approximate the effect of abnormal weather on non-gas revenues. The weather-normalization adjustment significantly reduces the impact of weather on gas-distribution earnings. In 2006, the Public Service Commission of Utah (PSCU) approved a pilot program for a “conservation enabling tariff” (CET) effective January 1, 2006, to promote energy conservation. Under the CET, Questar Gas non-gas revenues are decoupled from the volume of gas used by customers. The tariff specifies a margi n per customer for each month with differences to be deferred and recovered from customers or refunded to customers through periodic rate adjustments. The CET program, approved by the PSCU, allows for rate adjustments every six months. The adjustments will amortize deferred CET amounts over a 12-month period. These adjustments are limited to five percent of non-gas revenues.

Regulation

Questar Gas is regulated by the PSCU and the Public Service Commission of Wyoming (PSCW). The Idaho Public Utilities Commission has contracted with the PSCU for rate oversight of Questar Gas operations in a small area of southeastern Idaho. Questar Pipeline is regulated by the Federal Energy Regulatory Commission (FERC). Market Resources, through its subsidiary Clear Creek Storage Company, LLC, operates a gas-storage facility under the jurisdiction of the FERC. These regulatory agencies establish rates for the storage, transportation and sale of natural gas. The regulatory agencies also regulate, 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.

The Company applies the regulatory accounting principles prescribed under SFAS 71 “Accounting for the Effects of Certain Types of Regulation” to the rate-regulated businesses. Under SFAS 71, the Company records regulatory assets and liabilities that would not be recorded under GAAP for non-rate regulated entities. Regulatory assets and liabilities record probable future revenues or expenses associated with certain credits or charges that will be recovered from or refunded to customers through the rate-making process. See Note 7 to the consolidated financial statements for a description and comparison of regulatory assets and liabilities as of December 31, 2007 and 2006.

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.

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Purchased-Gas Adjustments

Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the PSCU and the PSCW. Purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. Questar Gas may hedge a portion of its natural gas supply to mitigate price fluctuations for gas-distribution customers. The regulatory commissions allow Questar Gas to record periodic mark-to-market adjustments for commodity-price derivatives in the purchased-gas-adjustment account.

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.

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 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 13). 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.

Contributions in aid of construction

Customer contributions in aid of construction reduce plant unless the amounts are refundable to customers. Contributions for main-line extensions may be refundable to customers if additional customers connect to the main line segment within five years. Refundable contributions are recorded as a long-term liability until refunded or the five-year period expires without additional customer connections. Amounts not refunded reduce plant. The Company offsets contributions recorded as a reduction of plant with capital expenditures in the Consolidated Statement of Cash Flows.

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:

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	Year ended December 31,
	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.

Major categories of fixed assets in gas-distribution, transportation and storage operations are grouped together and depreciated on a straight-line method. Under the group method, salvage value is not considered when determining depreciation rates. Gains and losses on asset disposals are recorded as adjustments in accumulated depreciation. The Company has not capitalized future-abandonment costs on a majority of its long-lived gas-distribution and transportation assets due to a lack of a legal obligation to restore the area surrounding abandoned assets. In these cases, the regulatory agencies have opted to leave retired facilities in the ground undisturbed rather than excavate and dispose of the assets. The following represent average depreciation and amortization rates of the Company’s capitalized costs:

	Year Ended December 31,
	2007	2006	2005
Questar Pipeline transportation, storage and other energy services	3.4%	3.5%	3.4%
Questar Gas distribution plant	3.1%	3.4%	3.9%

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 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 FERC, PSCU and PSCW require the capitalization of AFUDC during the construction period of rate-regulated plant and equipment. The Wexpro Agreement requires capitalization of AFUDC on cost-of-service construction projects. AFUDC on equity funds amounted to $2.0 million in 2007, $1.0 million in 2006 and $0.7 million in 2005 and increased interest and other income in the Consolidated Statements of Income. Interest expense was reduced for AFUDC on debt funds by $8.0 million in 2007, $0.8 million in 2006 and $1.0 million in 2005.

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:

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·

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

Bad-debt expense associated with accounts receivable for the year ended December 31, amounted to $2.6 million in 2007, $6.1 million in 2006 and $8.8 million in 2005. The allowance for bad-debt expenses was $6.0 million at December 31, 2007, and $7.8 million at December 31, 2006. Questar Gas’s retail-gas operations account for a majority of the bad-debt expense. Questar Gas estimates bad-debt expense as a percentage of general-service revenues with periodic adjustments. Uncollected accounts are generally written off six months after gas is delivered and interest is no longer accrued.

Income Taxes

Questar and its subsidiaries file a consolidated federal income tax return. Deferred income taxes are provided for the temporary differences arising between the book and tax-carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. Questar Gas and Questar Pipeline use the deferral method to account for investment tax credits as required by regulatory commissions. The Company records interest earned on income tax refunds in interest and other income and penalties and interest charged on tax deficiencies 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

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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.

Earnings Per Share (EPS)

Basic earnings per share are computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the accounting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options plus an estimated number of nonvested restricted shares. Questar’s common stock was split two-for-one June 18, 2007. Historical share and per-share amounts have been restated for the stock split.

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. Questar uses an accelerated method in recognizing share-based compensation costs with graded-vesting periods.

Defined Benefit Pension and Other Postretirement Plans

Questar adopted SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” on December 31, 2006. SFAS 158 requires an employer to recognize the overfunded or underfunded amounts of defined-benefit pension and postretirement plans as an asset or liability and recognize changes in the funded status of these plans in the year in which the changes occur through Other Comprehensive Income, if the changes are not recognized on the income statement. The effects of the provisions of SFAS 158 on the Company’s consolidated balance sheet are presented in the table below:

	Pension			Postretirement Benefits
	December 31,
	2007		2006	2007	2006
	(in millions)
Current liabilities	($  0.5)	($   1.1)
Noncurrent liabilities	(73.3)	(106.0)		($30.2)	($37.8)
Accumulated other comprehensive loss	47.5	68.9		8.8	13.5
Deferred income taxes	29.5	42.7		5.5	8.3

Comprehensive Income

Comprehensive income is the sum of net income as reported in the Consolidated Statement of Income and other comprehensive income or loss reported in the Consolidated Statement of Common Shareholders’ Equity. Other comprehensive income or loss includes changes in the market value of gas and oil price derivatives and recognition of the under-funded position of pension and other postretirement benefit plans. These transactions are not the culmination of the earnings process but result from periodically adjusting historical balances to fair value. Income or loss is realized when the physical gas, oil or NGL underlying the derivative instrument is sold or the pension or other postretirement benefit costs are accrued. The balances of accumulated other comprehensive income (loss), net of income taxes, were as follows:

	December 31,
	2007	2006
	(in millions)
Unrealized gain (loss) on derivatives	$ 31.0	$128.1
Pension liability	(47.5)	(68.9)

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Postretirement benefits liability	(8.8)	(13.5)
Accumulated other comprehensive income (loss)	($25.3)	$45.7

Income taxes allocated to each component of other comprehensive income (loss) for the year are shown in the table below:

	Year Ended December 31,
	2007	2006	2005
	(in millions)
Unrealized gain (loss) on derivatives	$59.0	($198.7)	$  95.5
Pension liability	(13.2)	29.4	5.7
Postretirement benefits liability	(2.9)	8.4
	$42.9	($160.9)	$101.2

Business Segments

Line of business information is presented according to senior management’s basis for evaluating performance considering differences in the nature of products, services and regulation. Certain intersegment sales include intercompany profit. Questar InfoComm Inc., previously a wholly-owned subsidiary of Questar, was transferred to Questar Pipeline effective January 1, 2007. The transaction was accounted for as a combination of entities under common control in a manner similar to a pooling of interests. Historical financial information was adjusted to reflect the combination for all periods presented in this report.

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 or to record a cumulative effect.

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.

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Note 2 – Earnings Per Share and Common Stock

Earnings per share (EPS)

Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options plus an estimated number of nonvested restricted shares. A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:

	Year Ended December 31,
	2007	2006	2005
	(in millions)
Weighted-average basic common shares outstanding	172.0	170.9	169.6
Potential number of shares issuable under the LTSIP	3.9	4.3	4.7
Average diluted common shares outstanding	175.9	175.2	174.3

In the past three years, Questar had the ability to issue shares under the terms of the Dividend Reinvestment and Stock Purchase Plan, Employee Investment Plan and Long-Term Stock Incentive Plan.

Dividend Reinvestment and Stock Purchase Plan (Reinvestment Plan)

The Reinvestment Plan allows parties interested in owning Questar common stock to reinvest dividends or invest additional funds in common stock. The Company can issue new shares or buy shares in the open market to meet shareholders’ purchase requests. The Company relied on open market purchases to meet 2007 and 2006 distributions and issued 5,350 shares in 2005. At December 31, 2007, 1,917,825, shares were reserved for future issuance.

Long-Term Stock Incentive Plan (LTSIP)

Questar issues stock options and restricted shares to certain officers, directors, and employees under its LTSIP. Stock options for participants have terms ranging from five to ten years with a majority issued with a ten-year term. Options held by employees generally vest in four equal, annual installments beginning six months after grant. Options granted to nonemployee directors generally vest in one installment six months after grant. Restricted shares vest in equal installments over a number of years after the grant date with the majority vesting in three or four-years. Nonvested restricted shares have voting and dividend rights; however, sale or transfer is restricted. Options and restricted shares issued prior to February 2006 vested on an accelerated basis in the event of a qualified termination, such as retirement, and have postretirement exercise periods. For a summary of LTSIP transactions see Note 3 - Share-Based Compensation following.

Note 3 – Share-Based Compensation

Prior to January 1, 2006, the Company accounted for share-based compensation using the intrinsic value method prescribed by 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 under APBO 25 and SFAS 123R. Restricted shares are valued at the grant-date market price and amortized to expense over the vesting period. Under SFAS 123R, the fair value of stock options is determined on the grant date using the Black-Scholes-Merton option-valuation model.

The Company implemented 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. 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. In 2007, income before income taxes and net income were approximately $1.6 million and $1.0 million lower, resulting in a $0.01 reduction in basic and diluted earnings per share. In 2006, income before income taxes and net income were approximately $1.7 million and $1.0 million lower, resulting in a $0.01 reduction in basic and diluted earnings per share.

Share-based compensation associated with unvested restricted shares for the 12 months ended December 31, 2007, 2006 and 2005, amounted to $11.3 million, $8.0 million and $4.2 million, respectively. At December 31, 2007, deferred share-based compensation amounted to $17.0 million, of which $14.0 million was attributed to unvested restricted stock grants. A year earlier deferred share-based compensation was $13.0 million, of which $9.8 million was attributed to unvested restricted stock.

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SFAS 123R requires reporting the benefits of tax deductions in excess of recognized compensation expense resulting from the exercise of share-based awards in the financing activities section of the Consolidated Statements of Cash Flow. This requirement reduced net cash provided from operating activities and increased net cash provided in financing activities by $11.1 million in 2007 and $12.0 million in 2006.

The following table shows pro forma net income had stock options been expensed in the 2005 period based on a fair value calculated using the Black-Scholes-Merton model:

		Year Ended December 31, 2005
		(in millions)
Net income, as reported		$325.7
Deduct: Share-based compensation expense
determined under fair-value-based methods, (after tax)		(1.7)
Pro forma net income	$324.0
Earnings per share
Basic, as reported	$1.92
Basic, pro forma	1.91
Diluted, as reported	1.87
Diluted, pro forma	1.86

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

	2007	2005
	February	January	October
Fair value of options at grant date	$41.08	$7.45	$10.73
Risk-free interest rate	4.77%	3.97%	4.17%
Expected price volatility	22.4%	29.9%	27.0%
Expected dividend yield	1.14%	1.77%	1.17%
Expected life in years	5.2	6.4	5.0

Long-Term Stock Incentive Plan

There were 10,222,228 shares available for future grant at December 31, 2007. Unvested stock options increased by 102,500 shares to 565,000 in 2007. Transactions involving stock options in the LTSIP for the three years ended December 31, 2007, are summarized below:

	Options Outstanding	Price Range	Weighted Average Price
Balance at January 1, 2005	8,030,142	$  6.85 - $17.55	$11.93
Granted	500,000	24.33 -   38.57	35.72
Exercised	(2,026,166)	6.85 -   17.55	11.42
Balance at December 31, 2005	6,503,976	6.85 -   38.57	13.91
Exercised	(1,131,268)	7.50 -   17.55	12.00
Balance at December 31, 2006	5,372,708	7.50 -   38.57	14.32
Granted	140,000	41.08	41.08
Exercised	(883,107)	7.50 -   17.55	12.78
Forfeited	(1,000)	14.01	14.01
Balance at December 31, 2007	4,628,601	$7.50 -   $41.08	$15.42

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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	822,616	2.0	$  7.71	822,616	$  7.71
9.57 – 11.98	959,745	4.0	11.53	959,745	11.53
13.56 – 14.86	2,185,164	4.4	13.71	2,185,164	13.71
17.55 – 24.33	121,076	6.9	23.15	96,076	22.84	25,000	$24.33
38.57 – 41.08	540,000	5.4	39.22			540,000	39.22
	4,628,601	4.1	$15.42	4,063,601	$12.20	565,000	$38.56

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

	Restricted Shares		Weighted Average
	Outstanding	Price Range	Price
Balance at January 1, 2005	476,880	$13.56 - $25.30	$16.09
Granted	227,950	24.33 -  43.02	26.99
Forfeited	(16,040)	14.36 -  25.50	18.24
Distributed	(88,708)	11.98 -  25.50	15.95
Balance at December 31, 2005	600,082	13.56 -  43.02	20.19
Granted	317,430	34.11 -  44.77	37.01
Forfeited	(5,290)	14.36 -  38.00	31.46
Distributed	(181,000)	13.56 -  43.02	13.87
Balance at December 31, 2006	731,222	13.56 -  44.77	28.04
Granted	369,156	38.96 -  56.65	45.03
Forfeited	(28,202)	18.45 -  49.97	37.96
Distributed	(243,252)	13.55 -  49.98	22.17
Balance at December 31, 2007	828,924	$13.56 - $56.65	$36.99

Note 4 – Property, Plant and Equipment

The details of property, plant and equipment and accumulated depreciation, depletion and amortization follow:

	December 31,
	2007	2006
	(in millions)
Property, plant and equipment
Market Resources
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
Questar E&P total	3,385.8	2,707.8
Wexpro	766.1	658.6
Gas Management	516.5	404.2

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Energy Trading and other	39.9	37.9
Market Resources total	4,708.3	3,808.5
Questar Pipeline	1,490.5	1,183.8
Questar Gas	1,539.2	1,418.0
Corporate	3.9	3.8
	$7,741.9	$6,414.1
Accumulated depreciation, depletion and amortization
Market Resources
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
Market Resources total	1,567.7	1,309.7
Questar Pipeline	441.9	411.6
Questar Gas	630.3	598.0
Corporate	3.4	3.4
	2,643.3	2,322.7
Net Property, Plant and Equipment	$5,098.6	$4,091.4

Questar E&P proved and unproved leaseholds had a net book value at December 31 of $381.1 million in 2007 and $343.3 million in 2006.

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.

Southern Trails Pipeline

The California segment of the Southern Trails Pipeline is currently not in service. Questar Pipeline is pursuing several options to sell or place this line in service.

Questar Pipeline performed an impairment test on the California segment of Southern Trails during the fourth quarter of 2005 and recognized an impairment of $16 million, reducing its net investment to approximately $35 million. The value realized by Questar Pipeline for the California segment of Southern Trails, either by putting the line in service or selling the line, may vary from this amount.

A firm-transportation contract for 40 Mdth per day, representing about 50% of the total capacity, on the eastern segment of Southern Trails Pipeline is up for renewal in mid-2008. The company is working with the shipper to extend the contract. In addition, the company is actively remarketing this capacity in the event the shipper elects not to renew. An impairment of the $98.2 million net investment in the eastern segment may be required if the company’s recontracting efforts result in significantly lower throughput or rates.

Note 5– Asset Retirement Obligations (ARO)

Questar 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 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:

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	2007	2006
	(in millions)
ARO liability at January 1,	$132.4	$78.2
Accretion	8.3	7.1
Liabilities incurred	8.9	11.1
Revisions	1.0	38.2
Liabilities settled	(1.5)	(2.2)
ARO liability at December 31,	$149.1	$132.4

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 defined in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the 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 6 – 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	(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

Note 7 – Rate Regulation and Other Regulatory Assets and Liabilities

Rate Regulation

Questar Gas Rate Changes

In December 2007, Questar Gas filed a general rate case in Utah requesting an increase in rates of $27.0 million, including an authorized return on equity of 11.25%. Hearings are scheduled in mid-2008 and a decision from the PSCU is expected in August 2008.

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In October 2006, the PSCU approved the company’s proposed “conservation-enabling tariff” (CET)  effective January 1, 2006. The purpose of the CET is to promote energy conservation. Under the company’s prior rate structure, Questar Gas revenues declined when temperature-adjusted average usage per customer decreased. Questar Gas revenues increased when temperature-adjusted average usage per customer increased. Under the CET, Questar Gas non-gas revenues are decoupled from the volume of temperature-adjusted gas used by customers. The tariff specifies a margin per customer for each month with differences to be deferred and recovered from customers or refunded to customers through periodic rate adjustments. The PSCU reviewed the initial results of the CET during 2007 and authorized Questar Gas to continue the program for two additional years. Any adjustments to revenues are limited to 5% of non-gas revenues during each 12-month period beginn ing in November. Questar Gas recorded a $2.5 million revenue increase in 2007 and a $1.7 million revenue reduction in 2006 in accordance with the CET.

Effective June 1, 2006, the PSCU approved a settlement of other issues and ordered Questar Gas to reduce the non-gas portion of customer rates by $9.7 million to reflect a reduction in depreciation rates, a change in capital structure, and recovery of pipeline integrity costs.

In January 2007, the PSCU approved a “demand-side management” program (DSM) effective January 1, 2007. Under the DSM, Questar Gas encourages the conservation of natural gas through advertising, rebates for efficient homes and appliances, and energy audits. The costs of the DSM are deferred and recovered from customers through periodic rate adjustments. DSM costs of $7.5 million were incurred during 2007 and $0.6 million were recovered from customers.

Other Regulatory Assets and Liabilities

The Company has other regulatory assets and liabilities in addition to purchased-gas adjustments. The rate-regulated entities recover the costs of assets but do not generally receive a return on these assets.

Following is a description of the Company’s regulatory assets:

·

Gains and losses on the reacquisition of debt by rate-regulated companies are deferred and amortized as interest expense over the would-be remaining life of the reacquired debt. The reacquired debt costs had a weighted-average life of approximately 10 years as of December 31, 2007.

·

The CET asset (liability) represents actual revenues received that are less than (in excess of) the allowed revenues. These amounts are recovered (refunded) through periodic rate adjustments.

·

The DSM program liability represents funds available for the program that exceed amounts expended to date. These amounts are refunded through periodic rate adjustments.

·

The costs of complying with pipeline-integrity regulations are recovered in rates subject to a PSCU order effective June 1, 2006. Costs incurred prior to June 2006 were deferred and will now be recovered over a three-year period. Actual current costs in excess of $1.4 million annually will be deferred and recovered in future rates.

·

Questar Gas has a regulatory asset that represents future expenses related to abandonment of Wexpro operated gas and oil wells. The regulatory asset will be reduced over an 18 year period following an amortization schedule that commenced January 1, 2003, or as cash is paid to plug and abandon wells.

·

Production taxes on cost-of-service gas production are recorded when the gas is produced and recovered from customers when taxes are paid, generally within 12 months.

·

The rate-regulated businesses are allowed to recover certain deferred taxes from customers over the life of the related property, plant and equipment.

Current regulatory assets are included with prepaid and other and long-term regulatory assets are shown on a separate line in the consolidated balance sheets. A list of regulatory assets follows:

	December 31,
	2007	2006
	(in millions)
Current regulatory assets
Demand side management	$5.6
Deferred production taxes	2.5	$4.3
Conservation enabling tariff	1.3
	$9.4	$4.3

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	December 31,
	(in millions)
	2007	2006
Long-term regulatory assets
Cost of reacquired debt	$13.3	$14.7
Questar Gas pipeline integrity costs	7.3	5.7
Asset retirement obligations – cost-of-service gas wells	3.9	4.2
Income taxes recoverable from customers	2.5	2.9
Other	1.4	0.9
	$28.4	$28.4

Following is a description of the Company’s regulatory liabilities:

·

A regulatory liability has been recorded for the collection of postretirement medical costs allowed in rates which exceed actual charges.

·

Income taxes refundable to customers arise from adjustments to deferred taxes.

Current regulatory liabilities are included with accounts payable and long-term regulatory liabilities are included with other long-term liabilities in the consolidated balance sheets. A list of regulatory liabilities follows:

	December 31, 2006
	(in millions)
Current regulatory liabilities
Conservation enabling tariff	$1.5
Demand-side management	1.2
	$2.7

	December 31,
	2007	2006
	(in millions)
Long-term regulatory liabilities
Postretirement medical	$4.9	$4.3
Income taxes refundable to customers	1.7	2.0
	$6.6	$6.3

Note 8 – Debt

The Company has short-term line-of-credit commitments from several banks under which it may borrow up to $380 million at December 31, 2007. These credit lines have interest rates generally below the prime interest rate. Commercial-paper borrowings with initial maturities of less than one year are backed by these short-term line-of-credit arrangements. These credit arrangements carry annual facility or commitment fees on the unused balance. The details of short-term debt are as follows:

	December 31,
	2007	2006
	(in millions)
Commercial paper with variable-interest rates	$260.6	$40.0
Weighted-average interest rate	5.70%	5.43%

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 compared to no amount outstanding at the end of 2006. This credit agreement carries an annual commitment fee of 0.115% of the unused balance. At December 31,

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2007, Market Resources could pay dividends of $851 million and Questar Gas could pay dividends of $123 million without violating the terms of their debt covenants.

On July 25, 2007, Market Resources extended the maturity on its revolving credit facility one year to August 9, 2012. On November 13, 2007, Questar Pipeline filed with the SEC to sell up to $200 million of notes and on January 15, 2008 issued $200 million of 5.83% Notes due 2018. On November 13, 2007, Questar Gas Company filed with the SEC to sell up to $150 million of notes. This filing has not yet been declared effective by the SEC.

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)
Market Resources
7.50% notes due 2011	$   150.0	$   150.0
6.05% notes due 2016	250.0	250.0
Revolving term loan, 5.55% at December 31, 2007, due 2012	100.0
Questar Pipeline
Medium-term notes 5.85% to 7.55%, due 2008 to 2018	310.5	310.5
Questar Gas
Medium-term notes 5.02% to 7.58%, due 2008 to 2018	263.0	273.0
Five-year term loan, 5.19% at December 31, 2007, due 2010	50.0	50.0
Total long-term debt outstanding	1,123.5	1,033.5
Less current portion	(101.3)	(10.0)
Less unamortized-debt discount	(1.0)	(1.1)
Total long-term debt	$1,021.2	$1,022.4

Maturities of long-term debt for the five years following December 31, 2007, are as follows:

	(in millions)
2008	$101.3
2009	42.0
2010	50.0
2011	332.0
2012	191.5

Note 9 – Financial Instruments and Risk Management

The carrying value and estimated fair values of Questar’s 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	$    14.2	$    14.2	$    24.6	$    24.6
Fair value of derivative contracts	85.9	85.9	204.5	204.5
Financial liabilities
Short-term debt	260.6	260.6	40.0	40.0

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Long-term debt	1,123.5	1,139.1	1,033.5	1,065.2
Fair value of derivative contracts	31.4	31.4	8.4	8.4

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.

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 Shareholders’ 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 10 – Income Taxes

Details of Questar’s 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	$  93.7	$141.6	$  97.8
Deferred	173.8	90.5	71.1
State
Current	5.9	12.5	12.2
Deferred	17.6	11.3	7.2
Deferred investment tax credits recognized	(0.4)	(0.4)	(0.4)
	$290.6	$255.5	$187.9

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 taxes statutory rate	35.0%	35.0%	35.0%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit	1.9	2.2	2.5
Domestic production benefit	(0.2)	(0.3)	(0.3)
Percentage depletion		(0.1)	(0.1)
Amortize investment-tax credits related to

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rate-regulated assets	(0.1)	(0.1)	(0.1)
Tax benefits from dividends paid to ESOP	(0.1)	(0.2)	(0.3)
Other	(0.1)		(0.1)
Effective income tax rate	36.4%	36.5%	36.6%

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

	December 31,
	2007	2006
	(in millions)
Deferred tax liabilities
Property, plant and equipment	$992.3	$798.3
Energy-price derivatives		18.9
Total deferred tax liabilities	992.3	817.2
Deferred tax assets
Energy-price derivatives	6.0
Employee benefits and compensation costs	43.9	53.3
Total deferred tax assets	49.9	53.3
Deferred income taxes – noncurrent	$942.4	$763.9

Deferred income taxes – current
Energy-price derivatives	$ 26.2	$58.3
Other	(21.3)	(23.3)
Deferred income taxes – current liability	$   4.9	$35.0

Note 11 – Commitments and Contingencies

Questar 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.

Commitments

Historically, 40 to 50% of Questar Gas gas-supply portfolio has been provided from cost-of-service reserves; however this amount dropped to 34% in 2007 because the Company shut in some production to take advantage of low purchase-gas costs. In 2007, the remainder of the gas supply was purchased using index-based or fixed-price contracts. Questar Gas has commitments to purchase gas for $197.6 million in 2008, $85.5 million in 2009, $50.4 million in 2010, $32.4 million in 2011 and $27.8 million in 2012. Generally, at the conclusion of the heating season and after a bid process, new agreements for the next heating season are put in place. Questar Gas bought natural gas under purchase agreements amounting to $374.8 million in 2007, $429.5 million in 2006 and $447.4 million in 2005. In addition, Questar Gas has contracted for underground storage. Questar Gas stores gas during off-peak periods (typically during the summer) and withdraws gas from storage to meet peak-gas demand (typically in t he winter).

Questar Gas has third-party transportation commitments requiring yearly payments of $5.3 million through 2018.

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:

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	(in millions)
2008	$  7.7
2009	7.6
2010	7.6
2011	7.3
2012	5.4
2013 through 2028	18.7

Questar sold its headquarters building under a sale-and-leaseback arrangement committing the Company to occupy the building through January 12, 2012. Questar has four renewal options of five years each, following expiration of the original lease in 2012. Minimum future payments under the terms of long-term operating leases for the Company’s primary office locations are as follows:

	(in millions)
2008	$6.5
2009	6.5
2010	6.3
2011	5.8
2012	3.7

Total minimum future-rental payments have not been reduced for sublease rentals of $0.2 million in 2008, $0.1 million in 2009, and $0.1 million in 2010. Total rental expense amounted to $5.8 million in 2007, $5.3 million in 2006 and $5.1 million in 2005. Sublease-rental receipts were $0.4 in 2007, $0.4 million in 2006 and $0.3 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 violatio ns 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 12 – Employee Benefits

Pension and Postretirement Benefits  

The Company has defined-benefit pension and postretirement medical and life insurance plans covering the majority of its employees. The Company’s Employee Benefits Committee (EBC) has oversight over investment of retirement-plan and postretirement-benefit assets. The EBC uses a third-party consultant to assist in setting targeted-policy ranges for the allocation of assets among various investment categories. The majority of retirement-benefit assets were invested as follows:

	Actual % Allocation		%
	December 31,		Policy
	2007	2006	Range
Domestic equity securities	43	44	40-50
Foreign equity securities	24	22	15-25
Debt securities	28	27	26-34

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Real estate securities	5	6	3-7
Other		1	0-3

Questar sets aside funds for Employee Retirement Income Security Act (ERISA) qualified retirement-benefit obligations to pay benefits currently due and to build asset balances over a reasonable time period to pay future obligations. Questar is subject to and complies with minimum-required and maximum-allowed annual contribution levels mandated by ERISA and by the Internal Revenue Code. Subject to the above limitations, the Company seeks to fund the qualified retirement plan in amounts approximately equal to the yearly expense. The Company also has a nonqualified pension plan that covers a group of 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&# 146;s general funds. The Company commingles ERISA-qualified postretirement-benefit obligation assets with those of the ERISA-qualified retirement plan as permitted by section 401(h) of the Internal Revenue Code. The EBC seeks investment returns consistent with reasonable and prudent levels of liquidity and risk.

The EBC allocates pension-plan and postretirement-medical-plan assets among broad asset categories and reviews the asset allocation at least annually. Asset-allocation decisions consider risk and return, future-benefit requirements, participant growth and other expected cash flows. These characteristics affect the level, risk and expected growth of postretirement-benefit assets.

The EBC uses asset-mix guidelines that include targets and permissible ranges for each asset category, return objectives for each asset group and the desired level of diversification and liquidity. These guidelines change from time to time based on an ongoing evaluation of each plan’s risk tolerance.

Responsibility for individual security selection rests with each investment manager, who is subject to guidelines specified by the EBC. These guidelines are designed to ensure consistency with overall plan objectives.

The EBC sets performance objectives for each investment manager that are expected to be met over a three-year period or a complete market cycle, whichever is shorter. Performance and risk levels are regularly monitored to confirm policy compliance and that results are within expectations.

Pension-plan guidelines prohibit transactions between a fiduciary and parties in interest unless specifically provided for in ERISA. No restricted securities, such as letter stock or private placements, may be purchased for any investment fund. Questar securities may be considered for purchase at an investment manager’s discretion, but within limitations prescribed by ERISA and other laws. There was no direct investment in Questar shares for the periods disclosed. Use of derivative securities by any investment managers is prohibited except where the committee has given specific approval or where commingled funds are utilized that have previously adopted permitting guidelines.

Pension-plan benefits are 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. 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 as determined by an employee’s years of service and generally limited to 170% of the 1992 contribution for employees who retired after January 1, 1993. The Company is amortizing its transition obligation over a 20-year period, which began in 1992.

The pension projected-benefit obligation and postretirement benefit accumulated benefit obligation were measured using discount rates at December 31, of 6.50% in 2007 and 5.75% in 2006. Changes in discount rates are included in changes in plan assumptions. Asset-return assumptions are based on historical returns tempered for expectations of future performance. Plan assets reflect the fair value of assets at December 31. Questar does not expect any plan assets to be returned during 2008. The pension plan accumulated benefit obligation was $340.0 million at December 31, 2007. Plan obligations and fair value of plan assets are shown in the following table:

	Pension			Postretirement Benefits
	2007		2006	2007	2006
	(in millions)
Change in benefit obligation
Benefit obligation at January 1,	$421.5	$377.6		$83.0	$80.0
Service cost	10.4	9.8		0.9	0.9
Interest cost	24.7	22.8		4.4	4.5
Change in plan assumptions	(38.3)	16.1		(6.0)

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Actuarial loss	14.3	10.1	0.4	3.0
Benefits paid	(14.2)	(14.9)	(6.4)	(5.4)
Benefit obligation at December 31,	418.4	421.5	76.3	83.0
Change in plan assets
Fair value of plan assets at January 1,	314.4	256.1	45.2	39.7
Actual return on plan assets	25.7	48.5	3.4	6.0
Contributions to the plan	18.7	24.7	3.9	4.9
Benefits paid	(14.2)	(14.9)	(6.4)	(5.4)
Fair value of plan assets at December 31,	344.6	314.4	46.1	45.2
Underfunded status (current and long-term)	($73.8)	($107.1)	($30.2)	($37.8)

The projected 2008 pension funding is expected to be $17.6 million. Estimated benefit-plan payments for the five years following 2007 and the subsequent five years aggregated are as follows:

	Pension	Postretirement Benefits
	(in millions)
2008	$  13.6	$ 4.8
2009	14.2	4.9
2010	14.8	4.9
2011	15.9	5.1
2012	17.4	5.1
2013 through 2017	121.1	27.4

Postretirement benefits other than pensions include an estimate of the effect of the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The drug benefit offered as part of postretirement medical coverage is actuarially equivalent to Part D of Medicare. Questar qualified for a federal subsidy available on benefits provided to plan participants which meet certain actuarial equivalence requirements. The $2.0 million reduction in the accumulated postretirement benefit obligation due to the expected future subsidy has been treated as an actuarial experience gain and is being amortized to expense in future years through a decrease in the amortization of the unrecognized net loss, in accordance with FASB Staff Position No. 106-2. The annual reduction in Questar’s other postretirement benefits expense due to the subsidy is approximately $0.3 million. Medicare Prescription Drug subsidy payments will be used to fund Company contributions.

The components of pension and postretirement benefits expense are as follows. The Company continues to measure periodic expense for the 12-month period ended December 31. The pension expense includes costs of both qualified and nonqualified pension plans:

	Pension			Postretirement Benefits
	Year Ended December 31,			Year Ended December 31,
	2007	2006	2005	2007	2006	2005
	(in millions)			(in millions)
Service cost	$10.4	$   9.8	$  9.0	$0.9	$ 0.9	$ 0.8
Interest cost	24.7	22.8	21.2	4.4	4.5	4.6
Expected return on plan assets	(24.1)	(21.0)	(19.8)	(3.4)	(3.0)	(3.0)
Prior service and other costs	1.2	1.5	1.6	1.9	1.9	1.9
Recognized net actuarial loss	7.2	6.2	3.9	0.2	0.2	0.1
Special-termination benefits	0.6	1.4	0.8
Accretion of regulatory liability				0.8	0.8	0.8
Amortization of early retirement costs			2.4
Periodic expense	$20.0	$20.7	$19.1	$4.8	$5.3	$5.2

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Assumptions at January 1, used to calculate pension and postretirement benefits expense for the years, were as follows:

	2007	2006	2005
Discount rate	5.75%	6.00%	6.50%
Rate of increase in compensation	4.00%	4.00%	4.00%
Long-term return on assets	8.00%	8.00%	8.25%
Health-care inflation rate	8.00% decreasing to 5.00% by  2011	9.00% decreasing to 5.00% in 2011	10.00% decreasing to 5.00% by 2011

The 2008 estimated pension expense is $19.3 million. In 2008, $3.1 million of estimated actuarial loss and $1.2 million of prior service cost for the pension plans will be amortized from accumulated other comprehensive income. The 2008 estimated post retirement expense is $3.9 million excluding amortization of a regulatory liability. In 2008, $1.9 million of net transition obligation for the postretirement benefit plans will be amortized from accumulated other comprehensive income.

Service costs and interest costs are sensitive to changes in the health-care inflation rate. A 1% increase in the health-care inflation rate would increase the yearly service and interest costs by $0.1 million and the accumulated postretirement-benefit obligation by $1.4 million. A 1% decrease in the health-care inflation rate would decrease the yearly service cost and interest cost by $0.1 million and the accumulated postretirement-benefit obligation by $1.3 million.

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 either 80% or 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. The EIP trustee purchases Questar shares on the open market as cash contributions are received. The Company recognizes expense equal to its yearly contributions, which amounted to $8.1 million, $6.7 million and $6.2 million for 2007, 2006 and 2005, respectively. The Company contributed 16,928 shares in 2005, and has subsequently relied on open-market purchases.

Note 13 – 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 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.

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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 14 – Operations by Line of Business

Questar’s major lines of business include gas and oil exploration and production (Questar E&P and Wexpro), midstream field services (Gas Management), energy marketing (Energy Trading), interstate gas transportation (Questar Pipeline), and retail gas distribution (Questar Gas). 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. Questar InfoComm Inc., previously a wholly-owned subsidiary of Questar, was transferred to Questar Pipeline effective January 1, 2007. Historical financial information was adjusted to reflect the combination for all periods presented in this report. Following is a summary of operations by line of business for the three years ended December 31, 2007:

		Questar	Interco.				Questar				Gas		Energy		Questar		Questar
		Consol.	Trans.				E&P		Wexpro		Managmt.		Trading		Pipeline		Gas			Corp.
		(in millions)
2007
Revenues
From unaffiliated customers		$2,726.6					$956.0		$21.6		$189.3		$504.4		$127.7		$927.6
From affiliated companies					($739.9)				155.7		17.0		484.1		78.2		4.9
Total revenues		2,726.6			(739.9)		956.0		177.3		206.3		988.5		205.9		932.5
Operating expenses
Cost of natural gas and other   products sold		917.1			(731.6)		2.2						955.3		4.0		687.2
Operating and maintenance		298.6			(1.5)		87.9		16.5		83.6		1.0		37.7		73.4
General and administrative		165.4			(1.9)		56.3		14.7		17.2		3.9		31.3		45.5			($1.6)
Production and other taxes		101.0					60.1		20.0		1.4		0.1		7.3		11.5			0.6
Depreciation, depletion and
amortization		369.1					243.5		31.2		19.1		1.3		35.0		38.8			0.2
Other operating expenses	33.2			(4.9)		32.8		4.9		0.4
Total operating expenses	1,884.4			(739.9)		482.8		87.3		121.7			961.6		115.3			856.4			(0.8)
Net gain (loss) from asset sales	(0.9)					(0.6)		(0.7)							0.4
Operating income	841.3					472.6		89.3		84.6			26.9		91.0			76.1			0.8
Interest and other income	20.0			(47.3)		6.2		1.9		0.2			34.0		2.4			7.4			15.2
Income from unconsol. affiliates	8.9					0.4				8.5
Interest expense	(72.2)			47.3		(25.2)		(2.0)		(6.9)			(28.4)		(21.7)			(23.8)			(11.5)
Income tax expense	(290.6)					(168.5)		(30.0)		(31.1)			(11.7)		(26.7)			(22.3)			(0.3)
Net income	$   507.4					$285.5		$59.2		$  55.3			$  20.8		$  45.0			$  37.4			$ 4.2
Identifiable assets	$5,944.2					$2,526.4		$459.8		$ 487.1			$207.7		$1,092.8			$1,163.0			$7.4
Goodwill	70.7					60.9									4.2			5.6
Investment in unconsol. affiliates	52.8									52.8
Capital expenditures	1,398.3					708.5		105.0		128.3			2.1		318.5			135.9
2006
Revenues
From unaffiliated customers	$2,835.6					$815.7		$19.7				$168.0		$656.0		$117.1			$1,059.1

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From affiliated companies		($950.1)		150.5	15.9	697.8	80.4	5.5
Total revenues	2,835.6	(950.1)	815.7	170.2	183.9	1,353.8	197.5	1,064.6
Operating expenses
Cost of natural gas and other   products sold	1,223.6	(941.6)	2.8			1,335.8	4.8	821.8
Operating and maintenance	286.8	(1.3)	73.6	14.7	92.4	0.8	33.4	73.2
General and administrative	135.0	(1.7)	42.4	11.3	12.2	4.0	25.3	41.9	($0.4)
Production and other taxes	108.7		58.3	30.3	0.6	0.2	7.3	11.6	0.4
Depreciation, depletion and
amortization	308.4		185.7	33.1	15.3	0.9	32.3	40.9	0.2
Other operating expenses	42.0	(5.5)	42.0	5.5
Total operating expenses	2,104.5	(950.1)	404.8	94.9	120.5	1,341.7	103.1	989.4	0.2
Net gain (loss) from asset sales	25.3		24.3	(0.1)	1.0		0.4	(0.3)
Operating income (loss)	756.4		435.2	75.2	64.4	12.1	94.8	74.9	(0.2)
Interest and other income (expense)	9.3	(39.0)	(3.7)	1.3		31.6	1.7	6.6	10.8
Income from unconsol. affiliates	7.5		0.4		7.1
Interest expense	(73.6)	39.0	(27.1)	(0.5)	(4.7)	(28.6)	(23.8)	(22.6)	(5.3)
Income tax expense	(255.5)		(150.9)	(26.0)	(24.2)	(5.5)	(27.3)	(21.9)	0.3
Net income	$444.1		$253.9	$50.0	$42.6	$9.6	$45.4	$37.0	$5.6
Identifiable assets	$5,064.7		$2,169.6	$375.7	$374.9	$233.5	$831.6	$1,068.7	$10.7
Goodwill	70.7		60.9				4.2	5.6
Investment in unconsol. affiliates	37.5				37.3	0.2
Capital expenditures	916.1		586.3	82.7	82.2	1.5	76.6	86.7	0.1
2005
Revenues
From unaffiliated customers	$2,724.9		$   620.6	$    21.7	$   141.5	$  884.9	$  99.8	$  956.4
From affiliated companies		($869.0)		132.3	13.7	632.4	84.5	6.1
Total revenues	2,724.9	(869.0)	620.6	154.0	155.2	1,517.3	184.3	962.5
Operating expenses
Cost of natural gas and other   products sold	1,371.3	(860.2)	4.2			1,501.7	5.4	720.2
Operating and maintenance	262.8	(0.8)	61.8	11.2	85.2	1.0	30.7	73.7
General and administrative	123.1	(1.9)	33.9	10.0	7.5	3.9	34.2	39.3	($3.8)
Production and other taxes	120.2		68.7	32.6	0.7	0.2	6.3	11.0	0.7
Depreciation, depletion and
amortization	250.3		134.7	26.9	11.3	0.9	30.5	45.8	0.2
Other operating expenses	35.4	(6.1)	18.8	6.7			16.0
Total operating expenses	2,163.1	(869.0)	322.1	87.4	104.7	1,507.7	123.1	890.0	(2.9)
Net gain (loss) from asset sales	4.7		1.1	(0.2)			3.8
Operating income	566.5		299.6	66.4	50.5	9.6	65.0	72.5	2.9
Interest and other income (expense)	9.0	(34.3)	0.6	0.9	0.3	30.0	(1.2)	5.0	7.7
Income from unconsol. affiliates	7.5		0.3		7.2
Interest expense	(69.4)	34.3	(23.7)	(0.1)	(3.1)	(30.2)	(22.4)	(20.2)	(4.0)
Income tax expense	(187.9)		(104.0)	(23.5)	(19.2)	(3.4)	(14.8)	(21.3)	(1.7)
Net income	$   325.7		$   172.8	$    43.7	$    35.7	$      6.0	$    26.6	$     36.0	$      4.9
Identifiable assets	$4,374.3		$1,656.4	$  305.9	$  301.2	$  237.7	772.2	$1,090.4	$    10.5
Goodwill	71.3		61.5				4.2	5.6
Investment in unconsol. affiliates	30.7		0.1		30.3	0.3
Capital expenditures	712.7		424.2	57.8	93.3	0.9	68.3	67.9	0.3

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Note 15 – Quarterly Financial and Stock-Price Information (Unaudited)

Questar’s common stock was split two-for-one June 18, 2007. Historical share and per-share amounts have been restated for the stock split. Following is a summary of quarterly financial and stock-price information:

	First	Second	Third	Fourth
	Quarter	Quarter	Quarter	Quarter	Year
	(in millions, except per-share amounts)
2007
Revenues	$872.1	$556.7	$497.4	$800.4	$2,726.6
Operating income	240.3	197.4	182.1	221.5	841.3
Net income	151.1	112.2	113.3	130.8	507.4
Basic earnings per common share	0.88	0.65	0.66	0.76	2.95
Diluted earnings per common share	0.86	0.64	0.64	0.74	2.88
Dividends per common share	0.1175	0.1225	0.1225	0.1225	0.485
Market price per common share
High	$45.58	$55.84	$58.75	$57.36	$58.75
Low	37.98	44.61	44.42	50.67	37.98
Close	$44.61	$52.85	$52.53	$54.10	$54.10
2006
Revenues	$911.4	$596.2	$555.2	$772.8	$2,835.6
Operating income	230.8	166.1	167.7	191.8	756.4
Net income	137.2	90.4	95.0	121.5	444.1
Basic earnings per common share	0.80	0.53	0.56	0.71	2.60
Diluted earnings per common share	0.78	0.52	0.54	0.69	2.54
Dividends per common share	0.1125	0.1175	0.1175	0.1175	0.465
Market price per common share
High	$42.85	$41.04	$45.51	$44.78	$45.51
Low	33.69	33.74	37.84	38.74	33.69
Close	$35.03	$40.25	$40.89	$41.53	$41.53

Note 16 – 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:

	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

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	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 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 -

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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 analysis of new data has led to progressive increases in estimates of original gas-in-place in the Lance Pool reservoirs at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. The Wyoming Oil and Gas Conservation Commission (WOGCC) has approved 10-acre-density drilling for Lance Pool wells on about 12,700 (gross) of the Company’s 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, t he 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

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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
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.

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	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.

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)

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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 CORPORATION
Schedule of Valuation and Qualifying Accounts
					Column D
			Column C		Deductions for
Column A Description	Column B Beginning Balance		Amounts charged to expense		accounts written off and other		Column E Ending Balance
	(in millions)
Year Ended December 31, 2007
Allowance for bad debts	$7.8		$2.6		($4.4)		$6.0
Allowance for notes receivable	3.1				(0.3)		2.8
Year Ended December 31, 2006
Allowance for bad debts	7.7	6.1		(6.0)		7.8
Allowance for notes receivable	3.2			(0.1)		3.1
Year Ended December 31, 2005
Allowance for bad debts	6.1	8.8		(7.2)		7.7
Allowance for notes receivable		3.2				3.2

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

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

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ITEM 9A.  CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures.

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, as of December 31, 2007. Based on such evaluation, such officers have concluded that, as of December 31, 2007, the Company’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company, including its consolidated subsidiaries, required to be included in the Company’s reports filed or submitted under the Exchange Act. The Company’s Chief Executive Officer and Chief Financial Officer also concluded that the controls and procedures were effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management including its principal executive and financial officers or persons performing similar functions as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls.

There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter ended December 31, 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

Questar’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(e). Questar’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.

The effectiveness of Questar’s internal control over financial reporting as of December 31, 2007, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report as follows:

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of

Questar Corporation

We have audited Questar Corporation’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Questar Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, o r disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Questar Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Questar Corporation as of December 31, 2007 and 2006, and the related consolidated statements of income, common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007 of Questar Corporation and our report dated February 22, 2008 expressed an unqualified opinion thereon.

/s/ Ernst &Young LLP

Salt Lake City, Utah

February 22, 2008  

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ITEM 9B.  OTHER INFORMATION.

There is no information to report in this section.

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERANCE.

The information requested in this item concerning Questar’s directors is presented in the Company’s definitive Proxy Statement under the section entitled “Election of Directors” and is incorporated herein by reference. A definitive Proxy Statement for Questar’s 2008 annual meeting will be filed with the Securities and Exchange Commission.

Information about the Company’s executive officers can be found in Item 1 of Part I in this Annual Report.

Information concerning compliance with Section 16(a) of the Exchange Act, is presented in the definitive Proxy Statement for Questar’s 2008 annual meeting under the section entitled “Section 16(a) Compliance” and is incorporated herein by reference.

The Company has a Business Ethics and Compliance Policy (Ethics Policy) that applies to all of its directors, officers (including its Chief Executive Officer and Chief Financial Officer) and employees. Questar has posted the Ethics Policy on its web site, www.questar.com. Any waiver of the Ethics Policy for executive officers must be approved only by the Company’s Board of Directors. Questar will post on its web site any amendments to or waivers of the Ethics Policy that apply to executive officers.

ITEM 11.  EXECUTIVE COMPENSATION.

The information required to be furnished pursuant to this item will be set forth under the caption “Executive Compensation” in the Proxy Statement, and is incorporated herein by reference.

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

The information requested in this item for certain beneficial owners is presented in Questar’s definitive Proxy Statement for the Company’s 2008 annual meeting under the section entitled “Security Ownership, Principal Holders” and is incorporated herein by reference. Similar information concerning the securities ownership of directors and executive officers is presented in the definitive Proxy Statement for the Company’s 2008 annual meeting under the section entitled “Security Ownership, Directors and Executive Officers” and is incorporated herein by reference.

Finally, information concerning securities authorized for issuance under the Company’s equity compensation plans as of December 31, 2007, is presented in the definitive Proxy Statement for the Company’s 2008 Annual Meeting of Shareholders under the section entitled “Equity Compensation Plan Information” and is incorporated herein by reference.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

The information requested in this item for related transactions involving the Company’s directors and executive officers is presented in the definitive Proxy Statement for Questar’s 2008 Annual Meeting of Shareholders under the sections entitled “Information Concerning the Board of Directors” and Certain Relationships – “Executive Officers.”

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES.

The information requested in this item for principal accountant fees and services is presented in the definitive Proxy Statement for Questar’s 2008 Annual Meeting of Shareholders under the section entitled “Audit Committee Report” and is incorporated herein by reference.

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PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a) and (c) Financial statements and financial statement schedules filed as part of this report are listed in the index included in Item 8 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).

Questar 10-K EXHIBIT INDEX

Exhibit No.

Description

  2.*

Plan and Agreement of Merger dated as of December 16, 1986, by and among the Company, Questar Systems Corporation, and Universal Resources Corporation. (Exhibit No. 2. to Current Report on Form 8-K dated December 16, 1986.)

  3.1.*

Restated Articles of Incorporation as amended effective May 19, 1998. (Exhibit No. 3.1. to Form 10-Q Report for Quarter ended June 30, 1998.)

  3.2.*

Bylaws as amended effective October 24, 2005. (Exhibit No. 3.2. to Form 10-Q Report for Quarter ended September 30, 2005.)

  4.2.*

Questar Dividend Reinvestment and Stock Purchase Plan. (Exhibit No. 4. to Current Report on Form 8-K dated February 8, 2000.)

10.1.*

Stipulation and Agreement, dated October 14, 1981, executed by Mountain Fuel; Wexpro; 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 Mountain Fuel Supply Company’s Form 10-K Annual Report for 1981.)

10.2.*¹

Questar Corporation Annual Management Incentive Plan, as amended and restated effective January 1, 2005.  (Exhibit No. 10.2. to Form 10-K Annual Report for 2004.)

10.3.* ¹

Questar Corporation Executive Incentive Retirement Plan, as amended and restated effective January 1, 2005. (Exhibit No. 10.3. to Form 10-K Annual Report for 2004.)

10.4.¹

Questar Corporation Long-term Stock Incentive Plan, as amended and restated effective August 7, 2007.

10.5. *¹

Questar Corporation Executive Severance Compensation Plan, as amended and restated effective October 23, 2007. (Exhibit No. 99.1 to Current Report on Form 8-K dated October 24, 2007.)

10.6.*¹

Questar Corporation Deferred Compensation Plan for Directors, as amended and restated effective January 1, 2005, adopted October 23, 2007. (Exhibit No. 99.2 to Current Report on Form 8-K dated October 24, 2007.)

10.7.¹

Questar Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2005, adopted August 7, 2007.

10.8.*¹

Questar Corporation Stock Option Plan for Directors, as amended and restated effective October 29, 1998. (Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended September 30, 1998.)

10.9.*¹

Form of Individual Indemnification Agreement dated February 9, 1993, between Questar Corporation and Directors. (Exhibit No. 10.11. to Form 10-K Annual Report for 1992.)

10.10.*¹

Questar Corporation Deferred Share Plan, as amended and restated effective January 1, 2003. (Exhibit No.10.10 to Form 10-K Annual Report for 2004.)

10.11.*¹

Questar Corporation Deferred Compensation Plan, as amended and restated effective January 1, 2003. (Exhibit No. 10.11 to Form 10-K Annual Report for 2004.)

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80

10.12.*¹

Questar Corporation Directors’ Stock Plan as approved May 21, 1996. (Exhibit No. 10.15. to Form 10-Q Report for Quarter ended June 30, 1996.)

10.13.*¹

Questar Corporation Deferred Share Make-Up Plan as amended and restated effective January 1, 2003. (Exhibit No. 10.13 to Form 10-K Annual Report for 2004.)

10.14.*¹

Questar Corporation Long-Term Cash Incentive Plan effective January 1, 2004. (Exhibit No. 10.14. to Form 10-K Annual Report in 2003.)

10.15.*¹

Employment Agreement between the Company and Keith O. Rattie effective February 1, 2004. (Exhibit No. 10.15. to Form 10-K Annual Report for 2003.)

10.16.*¹

Employment Agreement between the Company and Charles B. Stanley effective February 1, 2004. (Exhibit No. 10.16. to Form 10-K Annual Report for 2003.)

10.17.*¹

Questar Corporation Annual Management Incentive Plan II effective January 1, 2005. (Exhibit No. 10.18. to Form 10-K Annual Report for 2004.)

10.18.*¹

Form of Restricted Stock Agreement dated February 8, 2005, for shares granted to officers and key employees. (Exhibit No. 10.1 to Current Report on Form 8-K dated February 8, 2005.)

10.19.*¹

Form of Restricted Stock Agreement dated February 8, 2005, for shares granted to non-employee directors. (Exhibit No. 10.2 to Current Report on Form 8-K dated February 8, 2005.)

10.20.*¹

Form of Phantom Stock Agreement dated February 8, 2005, for phantom stock units granted to non-employee directors. (Exhibit No. 10.3 to Current Report on Form 8-K dated February 8, 2005.)

10.21.*¹

Amendment to Employment Agreement of Keith O. Rattie dated May 17, 2005. (Exhibit 10.23 to Current Report on Form 8-K dated May 18, 2005.)

10.22.*¹

Amendment to Employment Agreement of Charles B. Stanley dated May 17, 2005. (Exhibit 10.24 to Current Report on Form 8-K dated May 18, 2005.)

10.23.*¹

Form of Option Agreement dated October 24, 2005, for shares granted to key officers. (Exhibit No. 99.1 to Current Report on Form 8-K dated October 27, 2005.)

10.24.*¹

Questar Corporation Deferred Compensation Wrap Plan, effective January 1, 2005, as adopted on October 24, 2006. (Exhibit No. 10.1 to Form 10-Q Report for Quarter Ended September 30, 2006.)

10.25.*¹

Form of Restricted Stock Agreement dated February 14, 2006, for shares granted to certain key executives. (Exhibit No. 10.1 to Current Report on Form 8-K dated February 14, 2006.)

10.26.*¹

Form of Restricted Stock Agreement dated February 14, 2006, for shares granted to other officers and key employees. (Exhibit No. 10.2 to Current Report on Form 8-K dated February 14, 2006.)

10.27.*¹

Form of Restricted Stock Agreement dated February 14, 2006, for shares granted to non-employee directors. (Exhibit No. 10.3 to Current Report on Form 8-K dated February 14, 2006.)

10.28.*¹

Form of Phantom Stock Agreement dated February 14, 2006, for shares granted to non-employee directors. (Exhibit No. 10.4 to Current Report on Form 8-K dated February 14, 2006.)

10.29*¹

Form of Restricted Stock Agreement dated February 13, 2007, for shares granted to certain key executives. (Exhibit No. 10.1 to Current Report on Form 8-K dated February 13, 2007.)

10.30*¹

Form of Restricted Stock Agreement dated February 13, 2007, for shares granted to other officers and key employees. (Exhibit No. 10.2 to Current Report on Form 8-K dated February 13, 2007.)

10.31*¹

Form of Restricted Stock Agreement dated February 13, 2007, for shares granted to non-employee directors. (Exhibit No. 10.3 to Current Report on Form 8-K dated February 13, 2007.)

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10.32*¹

Form of Phantom Stock Agreement dated February 13, 2007, for shares granted to non-employee directors. (Exhibit No. 10.4 to Current Report on Form 8-K dated February 13, 2007.)

10.33*¹

Form of option agreement dated February 13, 2007, for options granted to certain key executives. (Exhibit No. 10.5 to Current Report on Form 8-K dated February 13, 2007.)

12.

Ratio of earnings to fixed charges.

14.*

Business Ethics and Compliance Policy (Exhibit No. 14. to Form 10-K Annual Report for 2005.)

21.

Subsidiary Information.

23.1.

Consent of Independent Registered Public Accounting Firm.

23.2.

Engineer’s Consent.

23.3.

Consent of Independent Petroleum Engineers and Geologists.

23.4.

Consent of H. J. Gruy and Associates, Inc.

24.

Power of Attorney.

31.1.

Certification signed by Keith O. Rattie, Questar’s Chairman, 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’s Senior Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.

Certification signed by Keith O. Rattie and S. E. Parks, Questar’s Chairman, President and Chief Executive Officer and Senior 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 indicated filing and are incorporated herein by reference.

¹Exhibit so marked is management contract or compensation plan or arrangement.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 26th day of February 2008.

QUESTAR CORPORATION

   (Registrant)

By /s/Keith O. Rattie

      Keith O. Rattie

      Chairman, 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/ Keith O. Rattie

Chairman, President and

Keith O. Rattie

Chief Executive Officer

(Principal Executive Officer)

/s/ S. E. Parks

Senior Vice President and

S. E. Parks

Chief Financial Officer

(Principal Financial and Accounting Officer)

* P. S. Baker, Jr.

Director

*Teresa Beck

Director

*R. D. Cash

Director

*L. Richard Flury

Director

*J. A. Harmon

Director

*Robert E. McKee III

Director

*Gary G. Michael

Director

*Keith O. Rattie

Director

*M. W. Scoggins

Director

*Harris H. Simmons

Director

*C. B. Stanley

Director

*Bruce A. Williamson

Director

February 26, 2008

*/s/ Keith O. Rattie

  Keith O. Rattie, Attorney in Fact

EXHIBIT INDEX

Exhibit No.

Description

  2.*

Plan and Agreement of Merger dated as of December 16, 1986, by and among the Company, Questar Systems Corporation, and Universal Resources Corporation. (Exhibit No. 2. to Current Report on Form 8-K dated December 16, 1986.)

  3.1.*

Restated Articles of Incorporation as amended effective May 19, 1998. (Exhibit No. 3.1. to Form 10-Q Report for Quarter ended June 30, 1998.)

  3.2.*

Bylaws as amended effective October 24, 2005. (Exhibit No. 3.2. to Form 10-Q Report for Quarter ended September 30, 2005.)

  4.2.*

Questar Dividend Reinvestment and Stock Purchase Plan. (Exhibit No. 4. to Current Report on Form 8-K dated February 8, 2000.)

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10.1.*

Stipulation and Agreement, dated October 14, 1981, executed by Mountain Fuel; Wexpro; 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 Mountain Fuel Supply Company’s Form 10-K Annual Report for 1981.)

10.2.*¹

Questar Corporation Annual Management Incentive Plan, as amended and restated effective January 1, 2005.  (Exhibit No. 10.2. to Form 10-K Annual Report for 2004.)

10.3.* ¹

Questar Corporation Executive Incentive Retirement Plan, as amended and restated effective January 1, 2005. (Exhibit No. 10.3. to Form 10-K Annual Report for 2004.)

10.4.¹

Questar Corporation Long-term Stock Incentive Plan, as amended and restated effective August 7, 2007.

10.5. *¹

Questar Corporation Executive Severance Compensation Plan, as amended and restated effective October 23, 2007. (Exhibit No. 99.1 to Current Report on Form 8-K dated October 24, 2007.)

10.6.*¹

Questar Corporation Deferred Compensation Plan for Directors, as amended and restated effective January 1, 2005, adopted October 23, 2007. (Exhibit No. 99.2 to Current Report on Form 8-K dated October 24, 2007.)

10.7.¹

Questar Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2005, adopted August 7, 2007.

10.8.*¹

Questar Corporation Stock Option Plan for Directors, as amended and restated effective October 29, 1998. (Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended September 30, 1998.)

10.9.*¹

Form of Individual Indemnification Agreement dated February 9, 1993, between Questar Corporation and Directors. (Exhibit No. 10.11. to Form 10-K Annual Report for 1992.)

10.10.*¹

Questar Corporation Deferred Share Plan, as amended and restated effective January 1, 2003. (Exhibit No. 10.10 to Form 10-K Annual Report for 2004.)

10.11.*¹

Questar Corporation Deferred Compensation Plan, as amended and restated effective January 1, 2003. (Exhibit No. 10.11 to Form 10-K Annual Report for 2004.)

10.12.*¹

Questar Corporation Directors’ Stock Plan as approved May 21, 1996. (Exhibit No. 10.15. to Form 10-Q Report for Quarter ended June 30, 1996.)

10.13.*¹

Questar Corporation Deferred Share Make-Up Plan as amended and restated effective January 1, 2003. (Exhibit No. 10.13 to Form 10-K Annual Report for 2004.)

10.14.*¹

Questar Corporation Long-Term Cash Incentive Plan effective January 1, 2004. (Exhibit No. 10.14. to Form 10-K Annual Report in 2003.)

10.15.*¹

Employment Agreement between the Company and Keith O. Rattie effective February 1, 2004. (Exhibit No. 10.15. to Form 10-K Annual Report for 2003.)

10.16.*¹

Employment Agreement between the Company and Charles B. Stanley effective February 1, 2004. (Exhibit No. 10.16. to Form 10-K Annual Report for 2003.)

10.17.*¹

Questar Corporation Annual Management Incentive Plan II effective January 1, 2005. (Exhibit No. 10.18. to Form 10-K Annual Report for 2004.)

10.18.*¹

Form of Restricted Stock Agreement dated February 8, 2005, for shares granted to officers and key employees. (Exhibit No. 10.1 to Current Report on Form 8-K dated February 8, 2005.)

10.19.*¹

Form of Restricted Stock Agreement dated February 8, 2005, for shares granted to non-employee directors. (Exhibit No. 10.2 to Current Report on Form 8-K dated February 8, 2005.)

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84

10.20.*¹

Form of Phantom Stock Agreement dated February 8, 2005, for phantom stock units granted to non-employee directors. (Exhibit No. 10.3 to Current Report on Form 8-K dated February 8, 2005.)

10.21.*¹

Amendment to Employment Agreement of Keith O. Rattie dated May 17, 2005. (Exhibit 10.23 to Current Report on Form 8-K dated May 18, 2005.)

10.22.*¹

Amendment to Employment Agreement of Charles B. Stanley dated May 17, 2005. (Exhibit 10.24 to Current Report on Form 8-K dated May 18, 2005.)

10.23.*¹

Form of Option Agreement dated October 24, 2005, for shares granted to key officers. (Exhibit No. 99.1 to Current Report on Form 8-K dated October 27, 2005.)

10.24.*¹

Questar Corporation Deferred Compensation Wrap Plan, effective January 1, 2005, as adopted on October 24, 2006. (Exhibit No. 10.1 to Form 10-Q Report for Quarter Ended September 30, 2006.)

10.25.*¹

Form of Restricted Stock Agreement dated February 14, 2006, for shares granted to certain key executives. (Exhibit No. 10.1 to Current Report on Form 8-K dated February 14, 2006.)

10.26.*¹

Form of Restricted Stock Agreement dated February 14, 2006, for shares granted to other officers and key employees. (Exhibit No. 10.2 to Current Report on Form 8-K dated February 14, 2006.)

10.27.*¹

Form of Restricted Stock Agreement dated February 14, 2006, for shares granted to non-employee directors. (Exhibit No. 10.3 to Current Report on Form 8-K dated February 14, 2006.)

10.28.*¹

Form of Phantom Stock Agreement dated February 14, 2006, for shares granted to non-employee directors. (Exhibit No. 10.4 to Current Report on Form 8-K dated February 14, 2006.)

10.29*¹

Form of Restricted Stock Agreement dated February 13, 2007, for shares granted to certain key executives. (Exhibit No. 10.1 to Current Report on Form 8-K dated February 13, 2007.)

10.30*¹

Form of Restricted Stock Agreement dated February 13, 2007, for shares granted to other officers and key employees. (Exhibit No. 10.2 to Current Report on Form 8-K dated February 13, 2007.)

10.31*¹

Form of Restricted Stock Agreement dated February 13, 2007, for shares granted to non-employee directors. (Exhibit No. 10.3 to Current Report on Form 8-K dated February 13, 2007.)

10.32*¹

Form of Phantom Stock Agreement dated February 13, 2007, for shares granted to non-employee directors. (Exhibit No. 10.4 to Current Report on Form 8-K dated February 13, 2007.)

10.33*¹

Form of option agreement dated February 13, 2007, for options granted to certain key executives. (Exhibit No. 10.5 to Current Report on Form 8-K dated February 13, 2007.)

12.

Ratio of earnings to fixed charges.

14.*

Business Ethics and Compliance Policy (Exhibit No. 14. to Form 10-K Annual Report for 2005.)

21.

Subsidiary Information.

23.1.

Consent of Independent Registered Public Accounting Firm.

23.2.

Engineer’s Consent.

23.3.

Consent of Independent Petroleum Engineers and Geologists.

23.4.

Consent of H. J. Gruy and Associates, Inc.

24.

Power of Attorney.

31.1.

Certification signed by Keith O. Rattie, Questar’s Chairman, President and Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

QUESTAR 2007 FORM 10-K

85

31.2.

Certification signed by S. E. Parks, Questar’s Senior Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.

Certification signed by Keith O. Rattie and S. E. Parks, Questar’s Chairman, President and Chief Executive Officer and Senior 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 indicated filing and are incorporated herein by reference.

¹Exhibit so marked is management contract or compensation plan or arrangement.

QUESTAR 2007 FORM 10-K

86

EX-10

Exhibit 10.4.

QUESTAR CORPORATION

LONG-TERM STOCK INCENTIVE PLAN

(As Amended and Restated Effective August 7, 2007)

Section 1.

Purpose

The Questar Corporation Long-Term Stock Incentive Plan (the “Plan”) is designed to encourage directors, officers and employees of and consultants to Questar Corporation and its affiliated companies (the “Company”) to acquire a proprietary interest in the Company, to generate an increased incentive to contribute to the Company’s future growth and success, and to enhance the Company’s ability to attract and retain talented individuals to serve the Company.  Accordingly, the Company, during the term of this Plan, may grant incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock, performance shares, and other awards valued in whole or in part by reference to the Company’s stock.  Any awards granted to a nonemployee director shall be solely to compensate such person for service to the Company as a nonemployee director.

Section 2.

Definitions

“Affiliate” shall mean any business entity to the extent that the Company would be deemed an “eligible issuer of service recipient stock” to the service providers of such entity, as determined pursuant to Treasury Regulation Section 1.409A-1(b)(5)(iii)(E).

“Award” shall mean a grant or award under Section 7 through 11, inclusive, of the Plan, as evidenced in a written or electronic document delivered to a Participant as provided in Section 13(b).

“Award Agreement” shall mean a written or electronic agreement between a Participant and the Company that sets forth the terms of the Award.

“Board” shall mean the Board of Directors of the Company.

“Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.

“Committee” shall mean the Management Performance Committee of the Board of Directors.

“Common Stock” or “Stock” shall mean the Common Stock, no par value, of the Company.

“Company” shall mean Questar Corporation.

“Covered Participant” shall mean a Participant who is a covered employee as defined in Section 162(m)(3) of the Code and the regulations promulgated pursuant to it or who the Committee believes will be such a covered employee for a Performance Period, and who the Committee believes will have remuneration in excess of $1 million for the Performance Period, as provided in Section 162(m) of the Code.

“Designated Beneficiary” shall mean the beneficiary designated by the Participant, in a manner determined by the Committee, to receive amounts due the Participant in the event of the Participant’s death.  In the absence of an effective designation by the Participant, Designated Beneficiary shall mean the Participant’s beneficiary designated under the Questar Corporation

Employee Investment Plan, if any, or, if none, the Participant’s beneficiary under the Company’s Basic Life Insurance Plan, if any, or, if none, the Participant’s estate.

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“Disability” shall mean permanent and total disability within the meaning of Section 105(d)(4) of the Code.

“Employee” shall mean any officer or employee of the Employer.

“Employer” shall mean the Company and any Affiliate.

“Fair Market Value” shall mean the regular closing benchmark price of the Company’s Common Stock reported on the New York Stock Exchange on the date in question, or, if the Common  Stock shall not have been traded on such date, the closing price on the next preceding day on which a sale occurred.

“Family Member” shall mean the Participant’s spouse, children, grandchildren, parents, siblings, nieces and nephews.

“Fiscal Year” shall mean the fiscal year of the Company.

“Incentive Stock Option” shall mean a stock option granted under Section 7 that is intended to meet the requirements of Section 422 of the Code.

“Nonemployee Director” shall mean a member of the Board who is not an Employee and who satisfies the requirements of Rule 16b-3(b)(3) promulgated under the Securities and Exchange Act of 1934 or any successor provision.

“Nonqualified Stock Option” shall mean a stock option granted under Section 7 that is not intended to be an Incentive Stock Option.

“Option” shall mean an Incentive Stock Option or a Nonqualified Stock Option.

“Participant” shall mean an Employee, Nonemployee Director, or consultant to whom an Award is granted under this Plan.

“Payment Value” shall mean the dollar amount assigned to a Performance Share which shall be equal to the Fair Market Value of the Common Stock on the day of the Committee’s determination under Section 9(c) with respect to the applicable Performance Period.

“Performance Goals” shall mean the objectives established by the Committee for a Performance Period pursuant to Section 12, for the purpose of determining the extent to which Performance Shares that have been contingently awarded for such Period are earned.

“Performance Period” or “Period” shall mean the period of years selected by the Committee during which the performance is measured for the purpose of determining the extent to which an Award of Performance Shares has been earned.

“Performance Share” shall mean an Award granted pursuant to Section 9 of the Plan expressed as a share of Common Stock.

“Restricted Period” shall mean the period of years selected by the Committee during which a grant of Restricted Stock or Restricted Stock Units may be forfeited to the Company.

“Restricted Stock” shall mean shares of Common Stock contingently granted to a Participant under Section 10 of the Plan.

“Restricted Stock Unit” shall mean a fixed or variable dollar denominated unit contingently awarded under Section 10 of the Plan.

“Right” shall mean a Stock Appreciation Right granted under Section 8.

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“Stock Unit Award” shall mean an Award of Common Stock or units granted under Section 11.

“Termination of Service” shall mean the date on which a Participant shall cease to serve as an Employee, Nonemployee Director, or consultant for any reason.

Section 3.

Administration

The Plan shall be administered by the Committee, unless such administration is delegated in whole or in part in accordance with the provisions below or unless otherwise determined by the Board. All references in the Plan to the Committee shall include such designee or other individual or administrative body (including the full Board) that has responsibility, in whole or in part, for the administration of the Plan. The Committee shall have sole and complete authority to adopt, alter and repeal administrative rules, guidelines and practices governing the operation of the Plan, and to interpret the terms and provisions of the Plan.  The Committee’s decisions shall be binding upon all persons, including the Company, stockholders, an Employer, Employees, Nonemployee Director, Participants, Designated Beneficiaries, and Family Members.  The Committee may correct any defect, supply any omission or rec oncile any inconsistency in the Plan or in any agreement entered into hereunder in the manner and to the extent it shall deem expedient and it shall be the sole and final judge of such expediency.  No member of the Committee shall be liable for any action or determination made in good faith.

The Committee or the Board may, from time to time, delegate to specified officers of the Company the power and authority to grant Awards under the Plan to specified groups of Employees, consultants and Non-Employee Directors, subject to such restrictions and conditions as the Committee or the Board, in their sole discretion, may impose.  The delegation shall be as broad or as narrow and extend for such period as the Committee or the Board shall determine.  Notwithstanding the foregoing, the power and authority to grant Awards to any Employee or consultant or Non-Employee Director who is covered by Section 16(b) of the Exchange Act shall not be delegated by the Committee or the Board.  In addition, all actions to be taken by the Committee under this Plan, insofar as such actions affect compliance with Section 162(m) of the Code, shall be limited to those members of the Board who are Nonemployee Directors and who are outside directors under Section 162(m).

Section 4.

Eligibility

Awards may only be granted to directors, officers and employees of or consultants to the Company or any Affiliate who have the capacity to contribute to the success of the Company.  When selecting Participants and making Awards, the Committee may consider such factors as the Participant’s functions and responsibilities and the Participant’s past, present and future contributions to the Company’s profitability and growth.

Nothing contained in the Plan or in any individual agreement pursuant to the terms of the Plan shall confer upon any Participant any right to continue in the employment or service of the Company or to limit in any respect the right of the Company to terminate the Participant’s employment or service at any time and for any reason.

Section 5.

Maximum Amount Available for Awards and Maximum Award

Of the total number of shares of Common Stock approved by the stockholders in March, 2001, there are 10,312,768 shares of Common Stock available for issuance under this Plan as of June 30, 2007 (taking into account the 2 for 1 Common Stock split that occurred on June 18, 2007).  Shares of Common Stock may be made available from the authorized but unissued shares of the Company or from

3

shares reacquired by the Company, including shares purchased in the open market.  In the event that an Option or Right expires or is terminated unexercised as to any shares of Common Stock covered thereby, or any Award in respect of shares is forfeited for any reason under the Plan, such shares, to the extent not precluded by applicable law or regulation, shall be again available for Awards pursuant to the Plan.

In the event that the Committee shall determine that any stock dividend, extraordi­nary cash dividend, recapitalization, reorganization, merger, consolidation, split-up, spin-off, combination, exchange of shares, warrants or rights offering to purchase Common Stock at a price substantially below fair market value or other similar corporate event affects the Common Stock such that an adjustment is required in order to preserve the benefits or potential benefits intended to be made available under this Plan, then the Committee, in its sole discretion, may take action.  The Committee may adjust any or all of the number and kind of shares that thereafter may be awarded or optioned and sold or made the subject of Rights under the Plan, the number and kind of shares subject to outstanding Options and other Awards, and the grant, exercise or conversion price with respect to any of the foregoing and/or, if deemed appropriate, make provision for a cash payment to a Participant or a person who has an outstanding Option or other Award.  

There is a maximum of 1,000,000 shares that can be the subject of Awards granted to any single Participant in any given fiscal year.

There is a maximum of 1,200,000 shares that can be the subject of Incentive Stock Options in any given fiscal year.  There is also a maximum of 2,000,000 shares that can be used for purposes other than options.

Section 6.

Termination of Service

In the event of a Participant’s Termination of Service, the Participant’s right to exercise an Option or receive any Award shall be determined by the Committee and provided in the Award Agreement subject to the general requirement that Incentive Stock Options cannot be exercised as an Incentive Stock Option for longer than three months after retirement or 12 months after death or Disability.

Section 7.

Stock Options

Grant.  Subject to the provisions of the Plan, the Committee shall have sole and complete authority to determine the individuals to whom Options shall be granted, the number of shares to be covered by each Option, the option price therefore and the conditions and limitations, applicable to the exercise of the Option.  The Committee shall have the authority to grant Incentive Stock Options, Nonqualified Stock Options, or both types of Options.

Special Rules, Incentive Stock Options.  In the case of Incentive Stock Options, the terms and conditions of such grants shall be subject to and comply with such rules as may be prescribed by Section 422 of the Code and any implementing regulations.  Incentive Stock Options shall not be granted to Participants who are not employees of the Company or its subsidiaries.  The aggregate Fair Market Value of Common Stock for which any Incentive Stock Options are exercisable for the first time by a Participant during any calendar year under the Plan or any other Plan of the Company or any subsidiary shall not exceed $100,000.  To the extent the Fair Market Value of the shares of Common Stock attributable to Incentive Stock Options first exercisable in any calendar year exceeds $100,000, the Option shall be treated as a Nonqualified Stock Option.

4

Option Price.  The Committee shall establish the option price at the time each Option is granted, which price shall not be less than 100 percent of the Fair Market Value of the Common Stock on the date of grant.

Exercise.  Each Option shall be exercisable at such times and subject to such terms and conditions as the Committee, in its sole discretion, may specify in the applicable Award or thereafter; provided, however, that in no event may any Option granted hereunder be exercisable earlier than six months after the date of such grant or after the expiration of ten years from the date of such grant.  The Committee may impose such conditions with respect to the exercise of Options, including without limitation, any conditions relating to the application of federal or state securities laws, as it may deem necessary or advisable.

No shares shall be delivered pursuant to any exercise of an Option until payment in full of the option price is received by the Company.  Such payment may be made in cash, or its equivalent, or, if and to the extent permitted by the Committee, by exchanging shares of Common Stock owned by the Participant (that are not the subject of any pledge or other security interest), or by a combination of the foregoing, provided that the combined value of all cash and cash equivalents and the Fair Market Value of any such Common Stock so tendered to the Company, valued as of the date of such tender, is at least equal to such option price.  A Participant may tender shares of Common Stock by actual delivery or by attestation.

The Committee may, in accordance with Section 409A of the Code, provide one or more means to enable Participants and the Company to defer delivery of shares of Common Stock upon exercise of an Option on such terms and conditions as the Committee may determine, including by way of example the manner and timing of making a deferral election, the treatment of dividends paid on shares of Common Stock during the deferral period and the permitted distribution dates on events.

Transferability.  Participants are allowed to transfer vested Nonqualified Stock Options to Family Members of family trusts, provided that such options were granted as of and after February 10, 1998 and provided that such transfers are made and transferred Options are exercised in accordance with procedural rules adopted by the Committee.

Section 8.

Stock Appreciation Rights

The Committee may, with sole and complete authority, grant Rights in tandem with an Option.  Rights shall not be exercisable earlier than six months after grant, shall not be exercisable after the expiration of ten years from the date of grant and shall have an exercise price of not less than 100 percent of the Fair Market Value of the Common Stock on the date of grant.

A Right shall entitle the Participant to receive from the Company an amount equal to the excess of the Fair Market Value of a share of Common Stock on the exercise of the Right over the grant thereof.  The Committee shall determine whether such Right shall be settled in cash, shares of Common Stock or a combination of cash and shares of Common Stock.

Section 9.

Performance Shares

The Committee shall have sole and complete authority to determine the Participants who shall receive Performance Shares and the number of such shares for each Performance Period and to determine the duration of each Performance Period and the value of each Performance Share.  There

5

may be more than one Performance Period in existence at any one time, and the duration of Performance Periods may differ from each other.

Once the Committee decides to use Performance Shares, it shall establish Performance Goals for each Period on the basis of criteria selected by it.  Any Performance Goals for Covered Participants shall be set and measured under the provisions of Section 12.

As soon as practicable after the end of a Performance Period, the Committee shall determine the number of Performance Shares that have been earned on the basis of performance in relation to the established Performance Goals.  Payment Values of earned Performance Shares shall be distributed to the Participant in accordance with the Award Agreement covering such Performance Shares, which document shall contain payment terms that comply with Section 409A of the Code. The Committee shall determine whether Payment Values are to be distributed in the form of cash and/or shares of Common Stock.  Any Payment Values payable for Covered Participants shall be determined under the provisions of Section 12.  

Section 10.

Restricted Stock and Restricted Stock Units

Subject to the provisions of the Plan, the Committee shall have sole and complete authority to determine the Participants to whom shares of Restricted Stock and Restricted Stock Units shall be granted, the number of shares of Restricted Stock and the number of Restricted Stock Units to be granted to each Participant, the duration of the Restricted Period during which and the conditions under which the Restricted Stock and Restricted Stock Units may be forfeited to the Company, and the other terms and conditions of such Awards.

Shares of Restricted Stock and Restricted Stock Units may not be sold, assigned, transferred, pledged or otherwise encumbered, except as herein provided, during the Restricted Period.  At the expiration of the Restricted Period, the Company shall deliver shares of Common Stock to the Participant or the Participant’s legal representative or otherwise make payment under the Award.  Payment for Restricted Stock Units shall be made by the Company in cash and/or shares of Common Stock, as determined at the sole discretion of the Committee.

Section 11.

Other Stock Based Awards

In addition to granting Options, Rights, Performance Shares, Restricted Stock, and Restricted Stock Units, the Committee shall have authority to grant Stock Unit Awards to Participants that can be in the form of Common Stock or units, the value of which is based, in whole or in part, on the value of Common Stock.  Subject to the provisions of the Plan, Stock Unit Awards shall be subject to such terms, restrictions, conditions, vesting requirements and Code Section 409A compliant payment rules as the Committee may determine in its sole and complete discretion at the time of grant.

Any shares of Common Stock that are part of a Stock Unit Award may not be assigned, sold, transferred, pledged or otherwise encumbered prior to the date on which the shares are issued or, if later, the date provided by the Committee at the time of grant of the Stock Unit Award.

Stock Unit Awards shall specify whether the Participant is required to pay cash in conjunction with such Award, provided, however, that the Participant shall be required to pay at least 50 percent of the Fair Market Value of any Common Stock purchased in connection with a Stock Unit Award, with such Fair Market Value calculated on the date the Award is granted.

6

Stock Unit Awards may relate in whole or in part to certain performance criteria established by the Committee at the time of grant.  Stock Unit Awards may provide for deferred payment schedules in accordance with Section 409A of the Code and/or vesting over a specified period of employment.  In such circumstances as the Committee may deem advisable, the Committee may waive or otherwise remove, in whole or in part, any restriction or limitation to which a Stock Unit Award was made subject at the time of grant.

In the sole and complete discretion of the Committee, an Award, whether made as a Stock Unit Award under this Section 11 or as an Award granted pursuant to Sections 7 through 10, may provide the Participant with dividends or dividend equivalents (payable on a current or deferred basis) and cash payments in lieu of or in addition to an Award; provided, however, that all such dividends or dividend equivalents or cash payments shall comply with Section 409A of the Code.

Section 12.

Special Provisions, Covered Participants

Awards subject to Performance Goals for Covered Participants under this Plan shall be governed by the conditions of this Section in addition to other applicable provisions of the Plan.

All Performance Goals relating to Covered Participants for a relevant Performance Period shall be established by the Committee by such date as is permitted under Section 162(m) of the Code.  Performance Goals may include alternate and multiple goals and may be based on one or more business and or financial criteria.  In establishing the Performance Goals for the Performance Period, the Committee may include one or any combination of the following criteria in either absolute or relative terms, for the Company or any business unit within it:  (a) total shareholder return; (b) return on assets, equity, capital or investment; (c) pre-tax or after-tax profit levels including earnings per share; earnings before interest and taxes; earnings before interest, taxes, depreciation and amortization; net operating profits after tax; net income; (d) cash flow and cash flow return on investment; (e) econom ic value added and economic profit; (f) growth in earnings per share; (g) levels of operating expense or other expense items as reported on the income statement, including operating and maintenance expense; (h) measures of customer satisfaction and customer service as surveyed; (i) reserve growth, production growth or ratio of reserves to production; (j) efficiency measures such as throughput or production increases; and (k) revenue and return on revenue.

Performance Goals must be objective and must satisfy third party objectivity standards under Section 162(m) of the Code and regulations promulgated pursuant to it.  The Award and payment of any Award under this Plan to a Covered Participant with respect to a relevant Performance Period shall be contingent upon the attainment of the Performance Goals that are specified in advance by the Committee.  The Committee shall certify in writing prior to approval of any such Award that such applicable Performance Goals relating to the Award are satisfied.  (Approved minutes of the Committee may be used for this purpose.)

The maximum Award that may be paid to any Covered Participant under the Plan pursuant to Sections 9, 11 and 12 for any Performance Period shall be $2 million, if paid in cash, or 400,000 shares of Stock, if paid in Stock.

Section 13.

General Provisions

Withholding.  The Employer shall have the right to deduct from all amounts paid to a Participant in cash any taxes required by law to be withheld in respect of Awards under this Plan.  In the case of payments of Awards in the form of Common Stock, the committee shall require the Participant to pay to

7

the Employer the amount of any taxes required to be withheld with respect to such Common Stock, or, in lieu thereof, the Employer shall have the right to retain (or the Participant may be offered the opportunity to elect to tender) the number of shares of Common Stock whose Fair Market Value equals the amount required to be withheld.

Awards.  Each Award shall be evidenced in a written or electronic document delivered to the Participant that shall specify the terms and conditions and any rules applicable to such Award.

Nontransferability.  Except as provided in Section 7(f), no Award shall be assignable or transferable, and no right or interest of any Participant shall be subject to any lien, obligation or liability of the Participant, except by will or the laws of descent and distribution.

No Rights as Stockholder.  Subject to the provisions of the applicable Award, no Participant or Designated Beneficiary shall have any rights as a stockholder with respect to any shares of Common Stock to be distributed under the Plan until becoming the holder of such shares.  Notwithstanding the foregoing, in connection with each grant of Restricted Stock hereunder, the applicable Award shall specify if and to what extent the Participant shall not be entitled to the rights of a stockholder in respect of such Restricted Stock.

Construction of the Plan.  The validity, construction, interpretation, administration and effect of the Plan and of its rules and regulations, and rights relating to the Plan, shall be determined solely in accordance with the laws of Utah.

Effective Date.  This amendment and restatement shall be effective as of August 7, 2007 and shall (i) replace the amended and restated Plan document that was effective on March 1, 2001 (which was approved subsequently by the stockholders of the Company), and (ii) incorporate any amendments subsequent thereto.  For avoidance of doubt, the terms of this Plan document take into account the 2 for 1 Common Stock split that occurred on June 18, 2007.

Duration of Plan.  The Plan, as amended and restated, shall terminate on February 28, 2011, unless the term is extended with approval of the Company’s shareholders.

Amendment of Plan.  The Board of Directors may amend, suspend or terminate the Plan or any portion thereof at any time, provided that no amendment shall be made without stockholder approval if such approval is necessary to comply with any tax or legal requirement.

Amendment of Award.  The Committee may amend, modify or terminate any outstanding Award with the Participant’s consent at any time prior to payment or exercise in any manner not inconsistent with the terms of the Plan, including without limitation, to change the date or dates as of which an Option or Right becomes exercisable; a Performance Share is deemed earned; Restricted Stock becomes nonforfeitable; or to cancel and reissue an Award under such different terms and conditions as it determines appropriate.

Repricing.  Except for adjustments pursuant to Section 5, the per share price for any outstanding Option or Right granted under terms of the Plan may not be decreased after the dates on which such Option or Right was granted.  Participants do not have the ability to surrender an outstanding Option or Right as consideration for the grant of a new Option or Right with a lower price.

8

409A.  It is the intention of the Company that Awards under this Plan not be subject to the additional tax imposed pursuant to Section 409A of the Code, and the provisions of this Plan and of Awards issued hereunder shall be construed and administered in accordance with such intent. To the extent Awards issued after the effective date of this restatement could become subject to Code Section 409A, the Company may, without Participant consent and in such manner as it deems appropriate or desirable, amend or modify any Award or delay the payment under any such Award to the minimum extent necessary to meet the requirements of Code Section 409A.

Section 14.

Change of Control

In the event of a Change of Control of the Company, all Options, Restricted Stock, and other Awards granted under the Plan shall vest immediately.

A Change in Control of the Company shall be deemed to have occurred if (i) any “person” (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934 (the “Exchange Act’)) other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, is or becomes the beneficial owner (as such term is used in Rule 13d-3 under the Exchange Act) of securities of the Company representing 25 percent or more of the combined voting power of the Company; or (ii) the following individuals cease for any reason to constitute a majority of the number of directors then serving:  individuals who, as of May 19, 1998, constitute the Company’s Board of Directors and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest, including but not limited to a co nsent solicitation, relating to the election of directors of the Company) whose appointment or election by the Board or nomination for election by the Company’s stockholders was approved or recommended by a vote of at least two-thirds of the directors then still in office who either were directors on May 19, 1998, or whose appointment, election or nomination for election was previously so approved or recommended; or (iii) the Company’s stockholders approve a merger or consolidation of the Company or any direct or indirect subsidiary of the Company with any corporation, other than a merger or consolidation that would result in the voting securities of the Company outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof) at least 60 percent of the combined voting power of the securities of the Company or such surviving entity or its parent outstandin g immediately after such merger or consolidation, or a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no person is or becomes the beneficial owner, directly or indirectly, of securities of the Company representing 25 percent or more of the combined voting power of the Company’s then outstanding securities; or (iv) the Company’s stockholders approve a plan of complete liquidation or dissolution of the Company or there is consummated an agreement for the sale or disposition by the Company of all or substantially all of the Company’s assets, other than a sale or disposition by the Company of all or substantially all of the Company’s assets to an entity, at least 60 percent of the combined voting power of the voting securities of which are owned by the stockholders of the Company in substantially the same proportions as their ownership of the Company immediately prior to such sale.  A Change in Control, however, shall not be considered to have occurred until all conditions precedent to the transaction, including but not limited to, all required regulatory approvals have been obtained.

9

Executed on the date set forth below to be effective for all purposes as set forth herein.

QUESTAR CORPORATION

Plan Sponsor

__________________________________

By:

Keith O. Rattie

Chairman, President & CEO

Date:______________________________

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EX-10

Exhibit 10.7.

QUESTAR CORPORATION

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

Amended and Restated effective January 1, 2005

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QUESTAR CORPORATION

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

(As Amended and Restated effective January 1, 2005)

ARTICLE I

PURPOSE

This Supplemental Executive Retirement Plan is intended to enable Questar Corporation and its participating affiliates to attract and retain key management personnel by providing them with supplemental retirement benefits to compensate them for the limitations imposed by federal tax laws on benefits payable from the Questar Corporation Retirement Plan.  This Plan is intended to be an unfunded, “top-hat” arrangement providing deferred compensation to “a select group of management or highly compensated employees,” with the meaning of Sections 201(2), 301(a)(3), and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended.

This Plan was amended and restated in its entirety after approval by Questar Corporation’s Board of Directors on February 8, 2005 in a good faith attempt at compliance with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended, as enacted by the American Jobs Creation Act of 2004.  The Plan is hereby amended and restated again, effective January 1, 2005, in good faith compliance with Section 409A, to reflect Internal Revenue Service final regulations and guidance issued subsequent to the February 8, 2005 amendment and restatement.  Nothing in this amendment and restatement or in the February 8, 2005 amendment and restatement is intended to constitute a material modification of the terms and conditions of the Plan with respect to amounts deferred prior to January 1, 2005.

ARTICLE II

DEFINITIONS

The following terms, when used herein, shall have the meanings set forth below, unless a different meaning is plainly required by the context:

2.1

“Accrued Benefit” has the meaning set forth in the Retirement Plan.

2.2

“Board” means the Board of Directors of Questar Corporation or any successor company.

2.3

“Change in Control” has the meanings set forth in Section 15.1.

2.4

“Code” means the Internal Revenue Code of 1986, as it may be amended from time to time.

2.5

“Committee” means the Management Performance Committee of the Company’s Board.

2.6

“Company” means Questar Corporation or any successor company, or, where the context requires, any Participating Corporation.

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2.7

“Compensation Limit” means the annual limit of compensation that may be taken into account for purposes of providing benefits under tax-qualified retirement plans, as specified in Section 401(a)(17) of the Code and updated from time to time.

2.8

"Disability" means a condition that renders a Participant unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months.  A Participant shall not be considered to be disabled unless he furnishes proof of the existence of such disability in such form and manner as may be required by regulations promulgated under, or applicable to, Code Section 409A.

2.9

“Distribution Date” has the meaning set forth in Section 7.3.

2.10

“Distribution Event” has the meaning set forth in Section 7.3.

2.11

“Earliest Retirement Age” has the meaning set forth in the Retirement Plan.

2.12

“EIRP” means the Company’s Executive Incentive Retirement Plan, as amended or restated from time to time.

2.13

“Eligible Employee” means an employee of the Company or any Participating Corporation that has an accrued benefit under the Retirement Plan and that (i) receives or is expected to receive compensation in any calendar year in excess of the Compensation Limit, or (ii) has deferred compensation under any of the Company’s non-qualified deferred compensation plans.

2.14

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

2.15

“Key Employee” means a “specified employee” defined in Code Section 409A(a)(2)(B)(i) and relevant guidance issued thereunder.

2.16

“Participant” means any Eligible Employee who has become a participant in the Plan pursuant to Article IV.

2.17

“Participating Corporation” means any entity that is affiliated with the Company and whose employees are or were covered by the Company’s Retirement Plan.

2.18

“Plan” means the plan set forth in and created by this document.

2.19

“Retirement Date” means the first date as of which any benefits under the Retirement Plan commence to either the Participant or the Participant’s spouse or beneficiary.

2.20

“Retirement Income” has the meaning given such term in the Retirement Plan.

2.21

“Retirement Plan” means the Questar Corporation Retirement Plan, as amended or restated from time to time, or any successor plan.  If not otherwise defined, capitalized words or terms used in the Plan shall have the same definitions used in the Retirement Plan.

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2.22

“Section 409A Change in Control” means a change in the ownership or effective control of the Company, or in the ownership of a substantial portion of the assets of the Company, as defined in Section 409A of the Code and the regulations thereunder, and any successor legislation or guidance that amends, supplements, or replaces same.

2.23

“Separation from Service” means a termination of employment as provided under Code section 409A and the regulations promulgated thereunder, as such may be amended, supplemented or replaced.

1.24

“Supplemental Retirement Benefit” means the retirement benefit payable to Participants and their beneficiaries under the terms of this Plan.

ARTICLE III

EFFECTIVE DATE

The Plan was originally effective January 1, 1987.  The Company’s Equalization Benefit Plan was merged into the Plan effective May 19, 1998.  This amended and restated Plan document is effective January 1, 2005.

ARTICLE IV

PARTICIPATION IN THE PLAN AND ELIGIBILITY FOR BENEFITS

4.1

General.  Any individual who was a Participant in this Plan as of December 31, 2004 shall continue to participate in the Plan on and after the effective date of this amendment and restatement.  Any individual who was not a Participant in the Plan as of December 31, 2004 shall become a Participant in the Plan if (and when) he or she becomes an Eligible Employee and receives written notification from the Committee, or its designee, that the individual has been selected to participate in the Plan.  Once a Participant, the individual shall be eligible to accrue Supplemental Retirement Benefits under the Plan.

4.2

Failure of Eligibility.  If the Committee determines, in its sole and absolute discretion, that any Participant is no longer an Eligible Employee or no longer qualifies as a member of a select group of management or highly compensated employees of the Employer, the Participant shall cease active participation in this Plan and all accruals under this Plan by or on behalf of the Participant shall cease.  The Committee’s determination shall be final and binding on all persons.

4.3

Vesting.  Each Participant who first becomes eligible to participate in this Plan prior to January 1, 2008 shall be vested in his or her Supplemental Retirement Benefits under the Plan upon becoming vested in his or her Accrued Benefit under the Retirement Plan.  Each Participant who first becomes eligible to participate in the Plan on or after January 1, 2008 shall vest in his or her Supplemental Retirement Benefits under the Plan upon the later of (i) the date he or she becomes vested in his or her Accrued Benefit under the Retirement Plan, or (ii) the earlier of (x) the date that is 13 months from the date such individual first becomes a Participant in the Plan, provided such individual remains in the employment of the Company or a Participating Company continuously throughout such 13 month period, (y) the date the Participant dies or becomes Disabled, or (z) the occurrence of a Section 409A Change in Control.  In the event the Participant terminates employment without having vested in his or her Supplemental Retirement Benefits under the Plan, all such benefits shall be forfeited immediately upon such termination of employment.

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ARTICLE V

SUPPLEMENTAL RETIREMENT BENEFITS

Supplemental Retirement Benefits shall generally be equal to (i) the total amount of Retirement Income that would have been payable under the Retirement Plan (whether to the Participant or his spouse or beneficiary) if the limitation on annual benefits imposed by Section 415 of the Code and the limitation on annual compensation imposed by Section 401(a)(17) of the Code were not applicable and the Participant had not voluntarily chosen to defer any compensation under the terms of the Company’s nonqualified deferred compensation plans, less (ii) the aggregate of (x) the actual Retirement Income payable under the Retirement Plan (whether to the Participant or his spouse or beneficiary) and (y) the benefits accrued under the EIRP (if any) (whether payable to the Participant or his spouse or beneficiary).  The specific amount of Supplemental Retirement Benefits payable shall be calculated in accordance wit h Article VI and Article VII hereof.

ARTICLE VI

PRE-CODE SECTION 409A SUPPLEMENTAL RETIREMENT BENEFITS

6.1

Applicability of Section.  This Article VI shall apply to that portion of a Participant’s Supplemental Retirement Benefit that is an “amount deferred’ prior to January 1, 2005 (“Pre 409A Benefit”), as determined pursuant to Section 409A, Treas. Regulation 1.409A-6(a)(3), and any subsequent guidance.  It is the intent of this Plan that all Pre 409A Benefits be grandfathered pursuant to the statutory effective date rules of Code Section 409A and not be subject to the requirements of, or tax due under, Code Section 409A.

6.2

Default Time and Form of Distribution.  Except as provided in Sections 6.3 or 6.4, below, Pre 409A Benefits shall be paid in the same form, to the same recipients, and at the same time as Retirement Income is paid under the Retirement Plan.

6.3

Option Forms of Distribution.  

(a)

Election of Option Form of Benefit.  A Participant has a one-time election to receive Pre 409A Benefits in a lump sum or in up to four annual installments, commencing on, or at a date specified by the Participant after, the Retirement Date.  Any such election must require that all Pre 409A Benefits (including credited interest thereon) be paid in full within five years of the Retirement Date.  The Participant shall make the election at least one year prior to the Retirement Date and shall indicate (i) whether distribution is to be made in a lump sum or in installments, and if installments, the number thereof, and (ii) the date on which distribution is to commence.  In the event a Participant selects an optional form of benefit and elects to commence distributions as of the Retirement Date, payment shall commence on such date or as soon thereafter as is administratively practicable.  If the Participant fails to make an election at least one year prior to the Retirement Date, distribution of the Participant’s Pre 409A Benefit shall commence in accordance with Section 6.2, above.

(b)

Lump Sum Default Upon Failure to Notify Participant.  Notwithstanding the foregoing, a Participant who has not been advised that he may receive Pre 409A Benefits and has not received an opportunity to make an optional form of distribution election at least one year prior to his Retirement Date shall receive any Pre 409A Benefit in one lump sum payment on the Retirement Date or as soon thereafter as is administratively practicable.

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6.4

Calculation of Optional Form of Benefit.  The Committee shall calculate all lump sum or annual installment distributions of Pre 409A Benefits by first determining the lump-sum present value of the Pre 409A Benefit on the Retirement Date using a standard mortality table referred to as the 1983 Group Annuity Mortality and an interest rate equal to 80% of the average of the IRS 30-year Treasury Securities Rates for the six-month period preceding the Participant’s Retirement Date (the “Pre 409A Lump Sum Amount”).  To the extent Pre 409A Benefits are paid after the Retirement Date, the Pre 409A Lump Sum Amount (to the extent not yet distributed) will be credited with monthly interest through the date(s) of distribution calculated using the appropriate 30-year Treasury bond quoted in the Wall Street Journal on the first business day of each month.  The appropriate 30-year Treasury bond s hall be the bond that has the closest maturity date (by month) preceding the date on which the interest is to be credited.

6.5

Effect of Death on Optional Form of Distribution.  

(a)

Death After Retirement Date.  In the event the Participant has selected (or will receive) an optional form of distribution pursuant to Section 6.3(a) or (b) and dies after the Retirement Date, Pre 409A Benefits (to the extent remaining) shall be paid to the beneficiary selected by the Participant pursuant to Article XIV below at the same time and in the same amounts as would have been paid to the Participant had he not died.

(b)

Death Prior to Retirement Date.  In the event the Participant has selected (or will receive) an optional form of distribution pursuant to Section 6.3(a) or (b) and dies prior to the Retirement Date, the Pre 409A Benefit as of the Retirement Date shall be calculated in accordance with the principles set forth in Article V, taking into account the death of the Participant and the effect such death has on the calculation of Retirement Income.  The Pre 409A Benefit (as calculated pursuant to the preceding sentence and Section 6.4) shall be payable to the beneficiary selected by the Participant pursuant to Article XIV below in accordance with the distribution election made by the Participant.

ARTICLE VII

SUPPLEMENTAL RETIREMENT BENEFITS SUBJECT TO CODE SECTION 409A.

7.1

Applicability of Section.  This Section 7 shall apply to that portion of a Participant’s Supplemental Retirement Benefit that is an “amount deferred’ on and after January 1, 2005 (“Post 409A Benefit”), as determined pursuant to Section 409A, Treas. Regulation 1.409A-6(a)(3), and any subsequent guidance.  It is the intent of this Plan that all distributions of Post 409A Benefits be made in accordance with the distribution requirements of Section 409A.

7.2

Distribution Elections.

(a)

Any individual that first becomes a Participant in the Plan on or after January 1, 2008 may, to the extent permissible under Code Section 409A and the guidance thereunder, elect the time and form of distribution of Post 409A Benefits from among the options available under Sections 7.3 and 7.4 below, provided such election is made within thirty (30) days of first becoming a Participant in the Plan.  Any such election must require that all Post 409A Benefits (including credited interest thereon) be paid in full within five years of the Distribution Date (defined below).  In the event the Participant fails to make timely such election or in the event such election is not permissible under Code Section 409A, the Participant’s Post 409A Benefits shall be distributed at the default time and in the default form specified in Sections 7.2(c), below.

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(b)

Any individual that first becomes a Participant in the Plan prior to January 1, 2008 may make an election on or prior to December 31, 2007 as to the time and form of distribution of Post 409A Benefits.  The election shall specify the time and form of distribution of Post 409A Benefits from the options available under Sections 7.3 and 7.4 below, and shall be consistent with the requirements of Code Section 409A and the transitional guidance issued thereunder.  Any such election must require that all Post 409A Benefits (including credited interest thereon) be paid in full within five years of the Distribution Date (defined below). If any distribution election submitted in accordance with this Section prior to December 31, 2006 either (i) relates to payments that a Participant would otherwise receive in 2006, or (ii) would cause payments to be made in 2006, such election shall not be effective.  If any di stribution election submitted in accordance with this Section on or after January 1, 2007 but prior to December 31, 2007 either (i) relates to payments that a Participant would otherwise receive in 2007, or (ii) would cause payments to be made in 2007, such election shall not be effective.  In the event the Participant does not timely make a valid and effective election under this Section, distribution shall commence pursuant to the default time and form of distribution established in 7.2(c), below.

(c)

Default.  The default time and form of distribution of Post 409A Benefits shall be a lump sum distribution as soon as administratively feasible following the later of (i) the Participant’s 55^th birthday, or (ii) the earliest to occur of the Participant’s death, Disability, or Separation from Service (as defined below).

7.3

Time of Distribution.  A Participant may elect to receive a distribution of Post 409A Benefits on, or at a designated date following, the later of (i) the Participant’s 55^th birthday, or (ii) the occurrence of any of the following (which shall be the “Distribution Event”):

(a)

the Participant’s Disability;

(b)

the Participant’s Separation from Service; or

(c)

the Participant’s death.

The Participant may designate different distribution dates for the different events specified in Section 7.3(a), (b), and (c), above; provided, however, that distribution cannot commence prior to the Participant’s 55^th birthday or later than the Participant’s 65^th birthday.  The actual date on which distribution commences shall be the “Distribution Date.”  

7.4

Forms of Distribution.  A Participant may elect to receive a distribution of Post 409A Benefits in a single lump sum or in up to four (4) annual installments commencing on the Distribution Date; provided, however, that all Post 409A Benefits shall be distributed within five (5) years of the Distribution Date.  The Participant may designate different forms of distribution for the different Distribution Events specified in Section 7.3 (a), (b), and (c), above.

7.5

Determination of Post 409A Benefit.  Post 409A Benefits shall be calculated in accordance with the principles set forth in Article V on the earliest to occur of (i) the Distribution Date, or (ii) the Participant’s actual Retirement Date under the Retirement Plan.  For purposes of clarity, the calculation of such benefit shall take into account the Participant’s marital status and any related subsidies as of the date such benefit is determined, and shall, in the event that the Participant’s death is the Distribution Event, take into account the effect that the death of the Participant has on the calculation of Retirement Income.

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7.6

Calculation of Benefits.  The Committee shall calculate all distributions of Post 409A Benefits by first determining the lump-sum present value of the Post 409A Benefit (as determined pursuant to Section 7.5) on the date on which such benefit is calculated pursuant to Section 7.5, using a standard mortality table referred to as the 1983 Group Annuity Mortality table and an interest rate equal to 80% of the average of the IRS 30-year Treasury Securities Rates for the six-month period preceding the Distribution Date (the “Post 409A Lump Sum Amount”).  To the extent Post 409A Benefits are paid after the date on which such benefits are calculated, the Post 409A Lump Sum Amount (to the extent not yet distributed) will be credited with monthly interest through the date(s) of distribution calculated using the appropriate 30-year Treasury bond quoted in the Wall Street Journal on the first business day of each month.  The appropriate 30-year Treasury bond shall be the bond that has the closest maturity date (by month) preceding the date on which the interest is to be credited.  

7.7

Effect of Death on Distributions.  

(a)

Death After Distribution Event.  In the event the Participant dies after a Distribution Event has occurred, Post 409A Benefits (to the extent remaining) shall be paid to the beneficiary selected by the Participant pursuant to Article XIV below at the same time and in the same amounts as would have been paid to the Participant had he or she not died.

(b)

Death as a Distribution Event.  In the event the Participant’s death is the Distribution Event for Post 409A Benefits, such benefits shall be paid to the beneficiary selected by the Participant pursuant to Article XIV below in accordance with the distribution election made by the Participant.

7.8

Key Employees.  In the event a Participant is a Key Employee, distribution of Post 409A Benefits on account of the Key Employee’s Separation from Service cannot commence before the date that is six (6) months after the date of the Key Employee’s separation from service (the “Key Employee Distribution Date”).  In such event, any and all payments that would otherwise be made to the Participant prior to the Key Employee Distribution Date shall be withheld by the Company until the Key Employee Distribution Date and paid on such date or as soon thereafter as is administratively feasible.  All delayed payments will be credited with interest as specified in Section 7.6, above.  This paragraph shall not apply to any payments that are attributable to a Distribution Event other than a Separation from Service or that would otherwise be (and are) made on or after the Key Employee Dis tribution Date.

ARTICLE VIII

FUNDING

The Supplemental Retirement Benefits payable under this Plan shall be paid by the Company and Participating Corporations out of general assets.  In its discretion, the Board may establish a trust fund or make other arrangements to assure payment of the Supplemental Retirement Benefits.  Until paid or made available to a Participant or beneficiary, all assets of any trust fund or any account established by the Company shall be solely the property of the Company and shall be subject to the claims of the general creditors of the Company by means of writs, orders of attachment, garnishment, levies of execution or any other manner in which a general creditor seeks to satisfy its claims against the Company.  The Participants and their beneficiaries shall be unsecured creditors of the Company with respect to the Supplemental Retirement Benefits provided for in this Plan.

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ARTICLE IX

ALLOCATION OF COSTS

The cost of Supplemental Retirement Benefits paid to or on behalf of Retired Participants shall be allocated to and be the responsibility of the Company and the Participating Corporations for which the Participants performed services, and shall be divided among the Company and the Participating Companies in the same manner as contributions under the Retirement Plan are divided with respect to such Participant.

ARTICLE X

ADMINISTRATION

10.1

Committee to Administer and Interpret Plan.  The Committee shall administer the Plan and shall have all discretion and power necessary for that purpose.  The Committee shall have the discretion, authority, and power to (i) make, amend, interpret, and enforce all appropriate rules and regulations for the administration of this Plan and (ii) decide or resolve any and all questions including interpretations of this Plan and determinations of eligibility to participate and to receive distributions under this Plan, as may arise in connection with this Plan.  Any individual serving on the Committee shall not vote or act on any matter relating solely to himself.  When making a determination or calculation, the Committee shall be entitled to rely on information supplied by a Participant, beneficiary, or the Company, as the case may be.  If a trust has been established, th e Committee shall direct the trustee concerning all payments from the trust fund in accordance with the provisions of the Plan and the trust agreement and shall have such other powers in the administration of the trust fund as may be conferred upon it by the trust agreement.  The Committee shall maintain all records of the Plan except records of the trust fund if a trust has been established.

10.2

Agents.  In the administration of this Plan, the Committee may, from time to time, employ agents (including officers and other employees of the Company) and delegate to them such administrative duties as it sees fit (including acting through a duly appointed representative) and may from time to time consult with counsel who may be counsel to the Company.

10.3

Binding Effect of Decisions.  The decision or action of the Committee with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan.

10.4

Indemnity of Committee.  The Company shall indemnify and hold harmless the members of the Committee and any employee to whom duties of the Committee may be delegated against any and all claims, losses, damages, expenses or liabilities arising from any action or failure to act with respect to this Plan, except in the case of willful misconduct by the Committee, any of its members, or any such employee.

10.5

Employer Information.  To enable the Committee to perform its functions, the Company shall supply full and timely information to the Committee on all matters relating to the compensation of its Participants, the date and circumstances of the disability (as defined above), death or Separation from Service of a Participant, and such other pertinent information as the Committee may reasonably require.

10.6

Agent for Legal Process.  The Committee shall be agent of the Plan for service of all legal process.

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ARTICLE XI

CLAIMS PROCEDURE

11.1

Filing a Claim.  All claims shall be filed in writing by the Participant, his or her beneficiary, or the authorized representative of either, by completing the procedures that the Committee requires.  The procedures shall be reasonable and may include the completion of forms and the submission of documents and additional information.  All claims under this Plan shall be filed in writing with the Committee according to the Committee’s procedures no later than one year after the occurrence of the event that gives rise to the claim.  If the claim is not filed within the time described in the preceding sentence, the claim shall be barred.

11.2

Review of Initial Claim.

(a)

Initial Period for Review of the Claim.  The Committee shall review all materials and shall decide whether to approve or deny the claim.  If a claim is denied in whole or in part, written notice of denial shall be furnished by the Committee to the claimant within a reasonable time after the claim is filed but not later than ninety (90) days after the Committee receives the claim. The notice shall set forth the specific reason(s) for the denial, reference to the specific plan provisions on which the denial is based, a description of any additional material or information necessary for the claimant to perfect his claim and an explanation of why such material or information is necessary, and a description of the Plan’s review procedures, including the applicable time limits and a statement of the claimant’s right to bring a civil action under ERISA section 502(a) followi ng a denial of the appeal.

(b)

Extension.  If the Committee determines that special circumstances require an extension of time for processing the claim, it shall give written notice to the claimant and the extension shall not exceed ninety (90) days.  The notice shall be given before the expiration of the ninety (90) day period described in Section 11.2(a) above and shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render its decision.

11.3

Appeal of Denial of Initial Claim.  The claimant may request a review upon written application, may review pertinent documents, and may submit issues or comments in writing.  The claimant must request a review within a reasonable period of time prescribed by the Committee.  In no event shall such a period of time be less than sixty (60) days.

11.4

Review of Appeal.

(a)

Initial Period for Review of the Appeal.  The Committee shall conduct all reviews of denied claims and shall render its decision within a reasonable time, but not less than sixty (60) days of the receipt of the appeal by the Committee. The claimant shall be notified of the Committee’s decision in a notice, which shall set forth the specific reason(s) for the denial, reference to the specific plan provisions on which the denial is based, a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to and copies of all documents, records, and other information relevant to the claimant’s claim, and a statement of the claimant’s right to bring a civil action under ERISA section 502(a) following a denial of the appeal.

(b)

Extension.  If the Committee determines that special circumstances require an extension of time for reviewing the appeal, it shall give written notice to the claimant and the extension shall not exceed sixty (60) days.  The notice shall be given before the expiration of the sixty (60) day period described in Section 11.3 above and shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render its decision.

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11.5

Form of Notice to Claimant.  The notice to the claimant shall be given in writing or electronically and shall be written in a manner calculated be understood by the claimant.  If the notice is given electronically, it shall comply with the requirements of Department of Labor Regulation § 2520.104b-1(c)(1)(i), (iii), and (iv).

11.6

Discretionary Authority of Committee.  The Committee shall have full discretionary authority to determine eligibility, status, and the rights of all individuals under the Plan, to construe any and all terms of the Plan, and to find and construe all facts.

ARTICLE XII

AMENDMENT OR TERMINATION

The Board may at any time amend, modify, or terminate this Plan; provided, however, that no such amendment may alter in any way the time, form, or amount of benefits payable to any retired Participant or their surviving spouse or beneficiary, nor shall any such amendment, modification, or termination adversely affect the rights of any Participant to receive Supplemental Retirement Benefits earned prior to such action.  Notwithstanding the foregoing, the Company may, in its sole discretion, amend the Plan without the consent of the Participant or his or her spouse or beneficiary (even if such amendment is adverse to their interests and/or benefit under the Plan) to the minimum extent necessary to meet the requirements of Code Section 409A.

ARTICLE XIII

SUCCESSOR TO THE COMPANY

The Company shall require any successor or assign, whether direct or indirect, by purchase, merger, consolidation or otherwise, to all or substantially all of the business and/or assets of the Company, to assume and agree to pay any Supplemental Retirement Benefits in the same manner and to the same extent that the Company would be required to perform if no such succession or assignment had taken place.

ARTICLE XIV

BENEFICIARIES

Each Participant may designate one or more beneficiaries to receive any lump sum or installment payments distributable under this Plan on or after the Participant’s death.  In the absence of an effective beneficiary designation as to all or any part of any lump sum or installment payments, payment of such amounts shall be made to the Participant’s beneficiary under the Questar Corporation Employee Investment Plan, if any, or, if none, to the designated beneficiary under the Company’s Basic Life Insurance Plan, if any, or, if none, to the personal representative of the Participant’s estate.

ARTICLE XV

CHANGE IN CONTROL

15.1

Payments.  

(a)

Section 409A Change in Control.  In the event that a Section 409A Change in Control of the Company occurs and a Participant dies, becomes Disabled, or experiences a Separation from Service within two years of the 409A Change in Control, the Participant (or his beneficiary) shall receive a lump-

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sum payment of all accrued Supplemental Retirement Benefits within 30 days of such death, Disability or Separation from Service; provided, however, that any Post 409A Benefit shall be subject to the provisions of Section 7.8.  

(b)

Other Change in Control.  In the event that a Change in Control occurs that is not a Section 409A Change in Control, and the Participant dies, becomes disabled, or experiences a Separation from Service within three years of the Change in Control, the Participant shall receive a lump sum payment of all Pre-409A Benefits within 30 days of such death, Disability, or Separation from Service, and the Participant’s Post 409A Benefit shall be distributed in accordance with the Participant’s elections under Article VII

(c)

Calculation of Benefits.  Supplemental Retirement Benefits (both Pre 409A and Post 409A) shall be calculated in accordance with the principles set forth in Article V and Article VII, except that the date of distribution established under this Section 15.1 shall be the Distribution Date for purposes of calculating such benefits.  To the extent the Distribution Date under this Section 15.1 precedes the Earliest Retirement Age under the Retirement Plan, the Supplemental Retirement Benefits payable shall be reduced by the applicable actuarial and supplemental factors set forth in the Plan for lump sum distributions, and, to the extent that the Retirement Plan’s applicable actuarial or supplemental factors do not contemplate a distribution as of such Distribution Date, the Committee shall extrapolate such factors in good faith, in its sole discretion.

15.2

Change in Control Definition.  A Change in Control of the Company shall be deemed to have occurred if (i) any “person” (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934 (the “Exchange Act’)) other than a trustee or other fiduciary holding securities under an employee benefit plan of the Company, is or becomes the beneficial owner (as such term is used in Rule 13d-3 under the Exchange Act) of securities of the Company representing 25 percent or more of the combined voting power of the Company; or (ii) the following individuals cease for any reason to constitute a majority of the number of directors then serving:  individuals who, as of May 19, 1998, constitute the Company’s Board of Directors and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election cont est, including but not limited to a consent solicitation, relating to the election of directors of the Company) whose appointment or election by the Board or nomination for election by the Company’s stockholders was approved or recommended by a vote of at least two-thirds of the directors then still in office who either were directors on May 19, 1998, or whose appointment, election or nomination for election was previously so approved or recommended; or (iii) the Company’s stockholders approve a merger or consolidation of the Company or any direct or indirect subsidiary of the Company with any corporation, other than a merger or consolidation that would result in the voting securities of the Company outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof) at least 60 percent of the combined voting power of the securities of the Company or such sur viving entity or its parent outstanding immediately after such merger or consolidation, or a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no person is or becomes the beneficial owner, directly or indirectly, of securities of the Company representing 25 percent or more of the combined voting power of the Company’s then outstanding securities; or (iv) the Company’s stockholders approve a plan of complete liquidation or dissolution of the Company or there is consummated an agreement for the sale or disposition by the Company of all or substantially all of the Company’s assets, other than a sale or disposition by the Company

12

of all or substantially all of the Company’s assets to an entity, at least 60 percent of the combined voting power of the voting securities of which are owned by the stockholders of the Company in substantially the same proportions as their ownership of the Company immediately prior to such sale.  A Change in Control, however, shall not be considered to have occurred until all conditions precedent to the transaction, including but not limited to, all required regulatory approvals have been obtained.

15.3

Payment of Legal Fees for Disputes Following a Change in Control.  The Company agrees to pay as incurred, to the full extent permitted by law, and in accordance with Section 409A, all legal fees and expenses which a Participant may reasonably incur as a result of any contest (regardless of the outcome thereof) by the Company, the Participant, or others following a Change in Control regarding the validity or enforceability of, or liability under, any provision of this Plan or any guarantee of performance thereof (including as a result of any contest by the Participant about the amount of any payment pursuant to this Plan), plus interest at the rate set forth Section 7.6, herein.  The foregoing right to legal fees and expenses shall not apply to any contest brought by a Participant (or other party seeking payment under the Plan) that is found by a court of competent jurisdiction to be frivolous or vexat ious.  

ARTICLE XVI

MISCELLANEOUS

16.1

No Assignment or Alienation.

(a)

General.  Except as provided in subsection (b) below, the Supplemental Retirement Benefits provided for in this Plan shall not be anticipated, assigned (either at law or in equity), alienated, or be subject to attachment, garnishment, levy, execution or other legal or equitable process.  Any attempt by any Participant or any beneficiary to anticipate, assign or alienate any portion of the Supplemental Retirement Benefits provided for in this Plan shall be null and void.

(b)

Exception: QDRO.  The restrictions of subsection (a) shall not apply to a distribution to an “alternate payee” (as defined in Code section 414(p)) pursuant to a “qualified domestic relations order” (“QDRO”) within the meaning of Code section 414(p)(11).  The Committee shall have the discretion, power, and authority to determine whether a domestic relations order is a QDRO.  Upon a determination that an order is a QDRO, the Committee shall direct the Employer or the Trustee, as the case may be, to distribute to the alternate payee or payees named in the QDRO as directed by the QDRO.

16.2

Not An Employment Contract.  This Agreement is not a contract of employment, and any Participant may terminate his or her employment, or his or her employment may be terminated by the Company, at any time, subject to the terms and conditions of any employment agreements between the Participant and the Employer.

16.3

Furnishing Information.  A Participant or his or her beneficiary shall cooperate with the Committee by furnishing any and all information requested by the Committee and take such other actions as may be requested in order to facilitate the administration of the Plan and the payment of benefits hereunder.

16.4

Payments to Incompetents.  If the Committee determines in its discretion that a benefit under this Plan is to be paid to a minor, a person declared incompetent or to a person incapable of handling the

13

disposition of his or her property, the Committee may direct payment of such benefit to the guardian, legal representative or person having the care and custody of such minor, incompetent or incapable person.  The Committee may require proof of minority, incompetence, incapacity or guardianship, as it may deem appropriate prior to distribution of the benefit.  Any payment of a benefit shall be a payment for the account of the Participant and the Participant’s beneficiary, as the case may be, and shall be a complete discharge of any liability under the Plan for such payment amount.

16.5

Court Order.  The Committee is authorized to make any payments directed by court order in any action in which the Plan or the Committee has been named as a party.  

16.6

Code Section 409A Savings Clause.  It is the intent of the Company that all payments and benefits under this Plan be made in accordance with Code Section 409A or an exception thereto.  To the extent that any payment or benefit would violate Code Section 409A the Committee shall delay or restructure such payment or benefit to the minimum extent necessary to avoid the application of Code Section 409A.

16.7

Distribution in the Event of Taxation.  If, for any reason, all or any portion of a Participant’s benefits under this Plan becomes subject to tax under Code Section 409A prior to receipt, a Participant may petition the Committee for a distribution of that portion of his or her benefit that has become taxable.  Upon the grant of such a petition, which grant shall not be unreasonably withheld, the Employer, or if applicable, the trustee, shall distribute to the Participant immediately available funds in an amount equal to the taxable portion of his or her benefit (which amount shall not exceed a Participant’s unpaid Supplemental Retirement Benefit under the Plan).  If the petition is granted, the tax liability distribution shall be made within 90 days of the date when the Participant’s petition is granted.  Such a distribution shall affect and reduce the benefits to be paid under this Plan.

16.8

Governing Law.  To the extent not preempted by federal law, this Plan shall be governed by the laws of the State of Utah, without regard to conflicts of law principles.

Executed on the date set forth below to be effective for all purposes as set forth herein.

QUESTAR CORPORATION

Plan Sponsor

__________________________________

By:

Keith O. Rattie

Chairman, President & CEO

Date:______________________________

14

EX-12

Exhibit 12.

Questar Corporation

Ratio of Earnings to Fixed Charges

	Year Ended December 31,
	2007	2006	2005
	(dollars in millions)
Earnings
Income before income taxes	$798.0	$699.6	$513.6
Less company’s share of earnings of
equity investees	(8.9)	(7.5)	(7.5)
Plus distributions from equity investees	10.4	7.1	10.0
Plus interest expense	72.2	73.6	69.4
Plus allowance for borrowed funds used
during construction	8.0	0.8	1.0
Plus interest portion of rental expense	3.7	3.1	2.5
	$883.4	$776.3	$589.0
Fixed Charges
Interest expense	$  72.2	$  73.6	$  69.4
Plus allowance for borrowed funds used
during construction	8.0	0.8	1.0
Plus interest portion of rental expense	3.7	3.1	2.5
	$  83.9	$  77.5	$  72.9
Ratio of Earnings to Fixed Charges	10.5	10.2	8.1

For purposes of this presentation, earnings represent income before income taxes adjusted for fixed charges, earnings and distributions of equity investees. Income before income taxes includes Questar’s share of pretax earnings of equity investees. Fixed charges consist of total interest charges (expensed and capitalized), amortization of debt issuance costs and losses from reacquired debt, and the interest portion of rental expense estimated at 50%.

EX-21

Exhibit 21.

SUBSIDIARY INFORMATION

Registrant Questar corporation has the following subsidiaries: Questar Market Resources Company, Questar Pipeline Company and Questar Gas company.  Each of these companies is a Utah corporation.

Questar Market Resources has the following subsidiaries: Wexpro Company, Questar Exploration and Production Company, Questar Energy Trading Company, Questar Gas Management Company and Questar Employee Services, Inc.  Questar Exploration and Production Company is a Texas corporation.  The other listed companies are incorporated in Utah.

Questar Exploration and Production Company has one wholly-owned subsidiary: Questar URC Company, a Delaware corporation.  Questar Exploration and Production Company also does business under the names Universal Resources Corporation, Questar Energy Company and URC Corporation

Questar Energy Trading Company has two subsidiaries: URC Canyon Creek Compression Company; and Questar Oil and Gas Company.  Both are Utah corporations.

Questar Pipeline Company has four subsidiaries: Questar Southern Trails Company, Questar Transportation Services Company, Questar Overthrust Pipeline Company and Questar InfoComm, Inc., all four are Utah corporations.  Questar Overthrust Pipeline Company does business as Overthrust Pipeline Company.

Questar InfoComm, Inc. has four subsidiaries: Questar Energy Services, Inc., Questar Project Employee Company, Questar Applied Technology Services, Inc. and Salt Lake Data Center Company.  All four are Utah corporations.

EX-23

Exhibit 23.1.

Consent of Independent Registered Public Accounting Firm

We consent to the inclusion in this Annual Report (Form 10-K) of Questar Corporation of our reports dated February 22, 2008, with respect to the consolidated financial statements and schedule of Questar Corporation and the effectiveness of internal control over financial reporting of Questar Corporation.

We consent to the incorporation by reference in the following Registration Statements:

  1.  Registration Statement (Form S-8 No. 33-15149) pertaining to the Questar Corporation Stock Option Plan for Directors,

  2.  Registration Statement (Post-effective Amendment No. 3 to Form S-8 No. 33-4436) pertaining to the Questar Corporation Employee Savings and Stock Purchase Plan,

  3.  Registration Statement (Form S-8 No. 33-40800) pertaining to the Questar Corporation Long-Term Stock Incentive Plan,

  4.  Registration Statement (Form S-8 No. 33-40801) pertaining to the Questar Corporation Stock Option Plan for Directors (additional shares),

  5.  Registration Statement (Form S-8 No. 33-48169) pertaining to the Questar Corporation Employee Stock Purchase Plan,

  6.  Registration Statement (Form S-8 No. 333-04951) pertaining to the Questar Corporation Stock Option Plan for Directors (additional shares),

  7.  Registration Statement (Form S-8 No. 333-04913) pertaining to the Questar Corporation Directors' Stock Plan,

  8.  Registration Statement (Form S-8 No. 33-48168) pertaining to the Questar Corporation Dividend Reinvestment and Stock Purchase Plan,

  9.  Registration Statement (Form S-3 No. 333-09643) pertaining to the Questar Corporation Dividend Reinvestment Plan,

10.  Registration Statement (Form S-8 No. 333-67658) pertaining to the Questar Corporation Long-Term Stock Incentive Plan, and

11.  Registration Statement (Form S-8 No. 333-89486) pertaining to the Questar Corporation Employee Investment Plan;

of our reports dated February 22, 2008, with respect to the consolidated financial statements and schedule of Questar Corporation and the effectiveness of internal control over financial reporting of Questar Corporation included in this Annual Report (Form 10-K) of Questar Corporation.

/s/ Ernst & Young LLP

Salt Lake City, Utah  

February 22, 2008

EX-23

Exhibit 23.2.

Engineer’s Consent

As independent petroleum engineers, we hereby consent to the reference of our appraisal reports for Questar Exploration and Production Company as of years ended December 31, 2004, 2005, 2006 and 2007, incorporated herein by reference into the following Registration Statements Forms S-8 (33-04436, 33-15149, 33-40800, 33-40801, 33-48168, 33-48169, 333-04913, 333-04951, 333-57548 and 333-89486)

/s/Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

Denver, Colorado

February 25, 2008

EX-23

Exhibit 23.3.

Consent of Independent Petroleum Engineers and Geologists

As independent petroleum engineers, we hereby consent to the inclusion of the information included in this Form 10-K with respect to the oil and gas reserves of Questar Exploration and Production Company as of years ended December 31, 2004, 2005, 2006, and 2007.  We hereby further consent to all references to our firm included in this Form 10-K and to the incorporation by reference in the Registration Statements on Forms S-8, Nos. 33-04436, 33-15149, 22-40800, 33-40801, 33-48168, 33-48169, 333-04913, 333-04951, 333-67658, and 333-89486.

NETHERLAND, SEWELL & ASSOCIATES, INC.

By:  /s/G. Lance Binder, P.E.

G. Lance Binder, P.E., P.E.

Executive Vice President

Dallas, Texas

February 22, 2008

EX-23

Exhibit 23.4.

Consent of H. J. Gruy and Associates, Inc.

We hereby consent to the use of the name H. J. Gruy and Associates, Inc. and of references to H. J. Gruy and Associates, Inc. and to the inclusion of and references to our reports, or information contained therein, dated January 25, 2005, January 31, 2005, January 13, 2006, January 18, 2006, January 19, 2007, and January 18, 2008, prepared for Questar Exploration and Production Company in the Annual Report on Form 10-K of Questar Corporation for the filing dated on or about February 25, 2008, and the incorporation by reference into the applicable previous filings with the Securities and Exchange Commission.  We are unable to verify the accuracy of the reserves and discounted present worth values contained therein because our estimates of reserves and discounted present worth have been combined with estimates of reserves and present worth prepared by other petroleum consultants.

H. J. GRUY AND ASSOCIATES, INC.

Texas Registration Number F-000637

By:  /s/Robert J. Naas

Name:  Robert J. Naas

Title:    Executive Vice President

February 28, 2007

Dallas, Texas

EX-24

Exhibit 24.

POWER OF ATTORNEY

We, the undersigned directors of Questar Corporation, hereby severally constitute Keith O. Rattie and S. E. Parks, and each of them acting alone, our true and lawful attorneys, with full power to them and each of them to sign for us and in our names in the capacities indicated below, the Annual Report on Form 10-K for 2007 and any and all amendments to be filed with the Securities and Exchange commission by Questar Corporation, hereby ratifying and confirming our signatures as they may be signed by the attorneys appointed herein to the Annual Report on Form 10-K for 2007 and any and all amendments to such Report.

Witness our hands on the respective dates set forth below.

Signature

Title

Date

/s/

Chairman of the Board,

2/12/08

Keith O. Rattie

President, and Chief Executive Officer

Director

/s/

Director

2/12/08

Phillips S. Baker, Jr.

/s/

Director

2/12/08

Teresa Beck

/s/

Director

2/12/08

R. D. Cash

/s/

Director

2/12/08

L. Richard Flury

/s/

Director

2/12/08

James A. Harmon

/s/

Director

2/12/08

Robert E. McKee III

/s/

Director

2/12/08

Gary G. Michael

/s/

Director

2/12/08

M. W. Scoggins

/s/

Director

2/12/08

Harris H. Simmons

/s/

Director

2/12/08

C. B. Stanley

/s/

Director

2/12/08

Bruce A. Williamson

EX-31

Exhibit 31.1.

CERTIFICATION

I, Keith O. Rattie, certify that:

1.

I have reviewed this annual report of Questar Corporation on Form 10-K for the period ending December 31, 2007;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

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

d)

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

5.

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

a)

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

b)

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

February 26, 2008

/s/Keith O. Rattie

Keith O. Rattie

Chairman, President and

Chief Executive Office

EX-31

Exhibit 31.2.

CERTIFICATION

I, S. E. Parks, certify that:

1.

I have reviewed this annual report of Questar Corporation on Form 10-K for the period ending December 31, 2007;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

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

d)

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

5.

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

a)

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

b)

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

February 26, 2008

/s/S. E. Parks

S. E. Parks

Senior Vice President and

Chief Financial Officer

EX-32

Exhibit No. 32.

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Questar Corporation (the Company) on Form 10-K for the period ending December 31, 2007, as filed with the Securities and Exchange Commission on the date hereof (the Report), Keith O. Rattie, Chairman, President and Chief Executive Officer of the Company, and S. E. Parks, Senior Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1)

The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

QUESTAR CORPORATION

February 26, 2008

/s/Keith O. Rattie

Keith O. Rattie

Chairman, President and

Chief Executive Officer

February 26, 2008

/s/S. E. Parks

S. E. Parks

Senior Vice President and

Chief Financial Officer