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, 2008

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

STATE OF UTAH	001-08796	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, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filer [X]	Accelerated filer [   ]
Non-accelerated filer [   ]   (Do not check if a smaller reporting company)	Smaller reporting company [   ]

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

Yes  [   ]

No  [X]

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. (June 30, 2008):  $12.2 billion.*

On January 31, 2009, 173,601,723 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 19, 2009.

*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.

TABLE OF CONTENTS

Page No.

2

2

3

Nature of Business

6

Exploration and Production – Questar E&P and Wexpro

7

Midstream Field Services – Questar Gas Management

8

Energy Marketing – Questar Energy Trading

9

Interstate Gas Transportation – Questar Pipeline

9

Retail Gas Distribution – Questar Gas

10

Corporate

11

Employees

11

Executive Officers

11

12

16

Exploration and Production – Questar E&P and Wexpro

16

Midstream Field Services – Questar Gas Management

19

Energy Marketing – Questar Energy Trading

19

Interstate Gas Transportation – Questar Pipeline

19

Retail Gas Distribution – Questar Gas

20

20

21

21

22

23

38

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

41

76

76

78

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78

78

78

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,

AND DIRECTOR INDEPENDENCE

78

78

79

82

Where You Can Find More Information

Questar Corporation (Questar or the Company) 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. These reports and other information can be read and copied at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549-0213. You can obtain copies of these materials from the Public Reference Section of the SEC, 100 F Street, N.E., Washington, D.C. 20549, at prescribed rates. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC also maintains an internet site at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including Questar.

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. Information contained on or connected to Questar’s web site which is not directly incorporated by reference into the Company’s Annual Report on Form 10-K should not be considered part of this report or any other filing made with the SEC.

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

Finally, you may request a copy of filings other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing or calling Questar, 180 East 100 South Street, P.O. Box 45433, Salt Lake City, Utah 84145-0433 (telephone number (801) 324-5699).

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

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difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to the following:

·

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

·

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

·

changes in industry trends;

·

changes in laws or regulations; and

·

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

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.

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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.

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.

NYMEX   The New York Mercantile Exchange.

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

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

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

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FORM 10-K

ANNUAL REPORT, 2008

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 70% of the Company’s operating income in 2008. 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 northwestern Louisiana. Questar E&P continues to conduct exploratory drilling to determine the commerciality of its inventory of undeveloped leaseholds located primarily in the Rocky Mountain region. Questar E&P seeks to maintain geographical and geological diversity with its two core areas. Questar E&P has in the past and may in the future pursue acquisition of producing properties through the purchase of assets or c orporate entities to expand its presence in its core areas or create a new core area.

Questar E&P reported 2,218.1 Bcfe of estimated proved reserves as of December 31, 2008. Approximately 72% of Questar E&P’s proved reserves, or 1,587.3 Bcfe, were located in the Rocky Mountain region of the United States, while the remaining 28%, or 630.8 Bcfe, were located in the Midcontinent region. Approximately 1,269.4 Bcfe of the proved reserves reported by Questar E&P at year-end 2008 were developed, while 948.7 Bcfe were proved undeveloped. The majority of the proved undeveloped reserves were associated with the Company’s Pinedale Anticline leasehold. Natural gas comprised about 91% of Questar E&P’s total proved reserves at year-end 2008. See Item 2 of Part I and Note 16 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company’s proved reserves.

Wexpro manages, develops and produces cost of service reserves for gas utility affiliate Questar Gas under the terms of the Wexpro Agreement, a long-standing comprehensive agreement with the states of Utah and Wyoming. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19-20% on its investment base. Wexpro’s investment base is its investment in commercial wells and related facilities adjusted for working capital and reduced for deferred income taxes and depreciation. The term of the Wexpro Agreement coincides with the productive life of the gas and oil properties covered therein. Wexpro’s investment base totaled $410.6 million at December 31, 2008. 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 49% of Questar Gas supply requirements during 2008 at prices that were lower than Questar Gas paid for purchased gas. Wexpro sells crude-oil production from certain oil-producing properties at market prices with the revenues used to recover operating expenses and to provide Wexpro a return on its investment. Any operating income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%.

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 producing properties and leasehold acreage, the marketing of gas and oil, and obtaining goods, services and labor. Its longer-term growth strategy depends, in part, on its ability to purchase reasonably-priced reserves and develop them in a low-cost and efficient manner.

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

Wexpro collected 87% of its 2008 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 leasehold acreage in the Rocky Mountain area is held under leases granted by the federal government and administered by federal agencies, principally the Bureau of Land Management (BLM). Current federal regulations restrict activities during certain times of the year on significant portions of Market Resources leasehold due to wildlife activity and/or habitat. Market Resources has worked with federal and state officials in Wyoming to obtain authorization for limited winter-drilling activities on the Pinedale Anticline and has developed measures, such as drilling multiple wells from a single pad location, to minimize the impact of its activities on wildlife and wildlife habitat. Various wildlife species inhabit 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.

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

MIDSTREAM FIELD SERVICES – Questar Gas Management

General: Gas Management generated approximately 11% of the Company’s operating income in 2008. 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. (Kern River Pipeline).

Fee-based gathering and processing revenues were 76% of Gas Management’s net operating revenues during 2008. Approximately 35% of Gas Management’s 2008 net gas-processing revenues were derived from fee-based processing agreements. The remaining revenues were derived from natural gas processing margins from keep-whole agreements that are exposed to the frac spread. A keep-whole contract insulates producers from frac-spread risk while a fee-based contract eliminates

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commodity price risk for the processing plant owner. To further reduce volatility associated with keep-whole contracts, Gas Management may enter into forward-sales contracts for NGL or hedge NGL prices and equivalent gas volumes with the intent to lock in a processing margin. Under a contract with Questar Gas, Gas Management also gathers cost-of-service volumes produced from properties operated by Wexpro.

Gas Management collected 8% of its 2008 revenues from affiliated companies, primarily Questar Gas.

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

ENERGY MARKETING – Questar Energy Trading

General: Energy Trading markets natural gas, oil and NGL and generated approximately 3% of the Company’s operating income in 2008. 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.

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 Item 7A and Notes 1 and 7 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for additional information relating to hedging activities.

INTERSTATE GAS TRANSPORTATION – Questar Pipeline

General: Questar Pipeline provides natural gas-transportation and underground storage services in Utah, Wyoming and Colorado. Questar Pipeline and subsidiaries generated approximately 9% of the Company’s operating income in 2008. 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 2,533 miles of interstate pipeline with total firm capacity commitments of 4,155 Mdth per day. Questar Pipeline’s core-transportation system is strategically located 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 50% of the White River Hub in western Colorado, which was placed in service in the fourth quarter of 2008. These facilities connect with six interstate pipeline systems and a major processing plant near Meeker, Colorado.

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 facilities near Price, Utah, which provide 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 13.2 years as of December 31, 2008. All of Questar Pipeline storage capacity is fully contracted with a weighted-average remaining life of 8.2 years as of December 31, 2008. 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 2008, Questar Pipeline transported 120.9 MMdth for Questar Gas compared to 113.8 MMdth in 2007. 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.

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Questar Pipeline also transported 608.1 MMdth during 2008, up 73% over 2007, for nonaffiliated customers to pipelines owned by Kern River Pipeline, Northwest Pipeline, Colorado Interstate Gas, TransColorado, Wyoming Interstate Company, Rockies Express Pipeline and other systems. The increase was a result of 2007 system expansions on the Overthrust Pipeline and the Questar Pipeline southern system. Rocky Mountain producers, marketers and end-users seek capacity on interstate pipelines that move gas to California, the Pacific 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.

Regulation: The FERC issued a final rule on Standards of Conduct in October 2008. The final rule, Order No. 717, eliminates the concept of energy affiliates and adopts a “functional approach” that applies standards of conduct to individual officers and employees based on their job functions, not on the company or division in which the individual works. The general principles of Standards of Conduct are: Non Discrimination, Independent Functioning, No Conduit and Transparency. These principles govern the relationship between transportation function employees and marketing function employees conducting transactions with affiliated pipeline and storage companies regulated by the FERC (transportation providers).

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 7% of the Company’s operating income in 2008. As of December 31, 2008, Questar Gas was serving 888,602 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 2008, Questar Gas added 14,995 customers, a 1.7% increase. The rate of customer growth is significantly less than prior years because of declines in housing construction.

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 $1.0 million revenue increase in 2008 as a result of a 1% 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 $18.4 million in 2008.

Questar Gas reduces gas supply risk with cost-of-service natural gas reserves. During 2008 Questar Gas satisfied 49% of its supply requirements with cost-of-service gas and associated royalty-interest volumes. Wexpro produces cost-of-service gas, 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-

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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 in its balancing account the economic results associated with hedging activities.

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 2008-09 heating season, Questar Gas had an estimated design-day demand of 1,196 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 transportation 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 10.0% 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 hedging activities.

Questar Gas filed a general rate case in Utah in December 2007. The PSCU allowed Questar Gas to increase its non-gas distribution revenues by an annualized $12.0 million beginning August 15, 2008. The PSCU authorized a 10.0% return on equity. Questar Gas filed a general rate case in Wyoming in August 2008.  Hearings are scheduled for the second quarter of 2009.

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 these costs and to record a regulatory asset for costs incurred to comply with this Act.

Corporate

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

Employees

At December 31, 2008, the Company had 2,457 employees, including 907 in Market Resources, 309 in Questar Pipeline, 1,173 in Questar Gas and 68 in Corporate.

Executive Officers of the Registrant

Primary Positions Held with the Company

and Affiliates, Other Business Experience

Keith O. Rattie

55

Chairman (2003); President (2001); Chief Executive Officer (2002); Director (2001); Chief Operating Officer (2001 to 2002); Director, Questar affiliates (2001).

Charles B. Stanley

50

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); Executive Vice President and Chief Operating Officer, Market Resources and Market Resources subsidiaries (2002).

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R. Allan Bradley

57

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).

Ronald W. Jibson

55

Senior Vice President, Questar (2008); President, Chief Executive Officer and Director, Questar Gas Company (2008); Executive Vice President, Questar Gas Company (2008); Vice President, Operations (2004).

Jay B. Neese

50

Senior Vice President, Questar (2005); Executive Vice President, Questar Market Resources and Market Resources subsidiaries (2005); Vice President, Questar, Questar Market Resources and Market Resources subsidiaries (2003); Assistant Vice President Questar and Assistant Vice President, Operations, Questar E&P (2001).

Stephen E. Parks

57

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 (1996); and Director Market Resources subsidiaries (1996).

Thomas C. Jepperson

54

Vice President and General Counsel, Questar (2005); Division Counsel (2000 to 2004).

Abigail L. Jones

48

Vice President Compliance (2007) and Corporate Secretary (2005); Assistant Secretary (2004 to 2005).

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, revenue, operating result, cash flow, return on invested capital, and rate of growth. Because approximately 91% of Market Resources’ proved reserves at December 31, 2008, were natural gas, the Company’s revenue, margin, cash flow, net income and return on invested capital are substantially more sensitive to changes in natural gas prices than to changes in oil prices.

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;

•

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

•

domestic and global economic conditions;

•

domestic political developments;

•

weather conditions;

•

domestic and foreign government regulations and taxes;

•

technological advances affecting energy consumption and energy supply;

•

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

•

conservation efforts;

•

the price, availability and acceptance of alternative fuels;

•

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

•

the quality of gas and oil produced.

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A slowdown in economic activity caused by an extended recession would likely reduce domestic and worldwide demand for energy and result in lower natural gas, oil and NGL prices. Oil prices declined from record levels in early July 2008 of over $140 per Bbl to below $40 per Bbl in January 2009, while NYMEX natural gas prices have declined from over $13 per Mcf to below $4 per Mcf over the same period. In addition, the forecasted prices for the remainder of 2009 have also declined.

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 natural gas and oil prices, causing periodic shortages. There have also been regional shortages of drilling rigs and other equipment, as demand for specialized rigs and equipment has increased along with the number of wells being drilled. These factors also cause increases in costs for equipment, services and personnel. These cost increases could impact profit margin, cash flow and operating results or restrict the ability to drill wells and conduct operations, especially during periods of lower natural gas and oil prices.

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. Accidents or other operating risks could further result in loss of service available to the Com pany’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 a material adverse effect on the Company’s financial condition and operations.

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

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. Liquidity in the global-credit markets has severely contracted, making terms for certain financings less attractive, and in certain cases, resulted in the unavailability of certain types of financing. In lieu of commercial paper issuance, the Company at times has utilized back-up lines of credit with banks to meet short-term funding needs. Banks may be unable or unwilling to extend back-up lines of credit in the future. All of Questar’s bank loans are floating-rate debt. Fr om 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. While management believes it is important to maintain investment grade credit ratings to conduct the Company’s businesses, the Company may not be able to keep investment grade ratings.

The severe economic recession increases credit risk. Questar has significant credit exposure in outstanding accounts receivable from customers in all segments of its business. Questar is tightening its credit procedures such as requiring deposits or prepayments to help manage this risk. Questar also aggressively pursues collection of past-due accounts receivable.

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 increases 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. Questar is exposed to the risk of counterparties not performing.

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 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.

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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.

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.

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

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 natural gas transportation and oversees natural gas marketing. 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.

During the fourth quarter of 2008, FERC issued a number of orders related to market transparency that extend FERC oversight to many Questar subsidiaries. Order No. 704 requires all natural gas companies to report gas purchases and sales and their relationship to price reporting indexes. Order No. 712 defines changes in capacity release and asset management. Order No. 717 establishes new Standards of Conduct Rules and Order No. 720 requires intrastate pipelines to report available transportation capacity. In addition to the new orders, FERC released a policy statement on compliance in which it states that companies must have a “rigorous” FERC compliance program that extends to all subsidiaries, not just interstate pipelines. Since the enactment of the Energy Policy Act of 2005, granting FERC increased penalty authority for non compliance, FERC has targeted various issues in the natural gas industry for compliance audits and investigations.  

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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 and decisions 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, 2008. Questar E&P’s reserve estimates are prepared by Ryder Scott Company 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 reserves of subsidiaries with a significant minority interest. At December 31, 2008, approximately 93% of Questar E&P’s estimated proved reserves were Company operated. All reported reserves are located in the United States.

Estimated proved reserves
Natural gas (Bcf)	2,028.5
Oil and NGL (MMbbl)	31.6
Total proved reserves (Bcfe)	2,218.1
Proved developed reserves (Bcfe)	1,269.4

Questar E&P’s reserve statistics for the years ended December 31, 2006 through 2008, are summarized below:

Year	Year End Reserves (Bcfe)	Proved Gas and Oil Reserves Annual Production (Bcfe)	Reserve Life (Years)
2006	1,631.4	129.6	12.6
2007	1,867.6	140.2	13.3
2008	2,218.1	171.4	12.9

Questar E&P proved reserves by major operating areas at December 31, 2008 and 2007 follow:

	2008		2007
	(Bcfe)	(% of total)	(Bcfe)	(% of total)
Pinedale Anticline	1,164.9	53	1,033.9	55
Uinta Basin	258.8	12	301.2	16
Rockies Legacy	163.6	7	158.6	9
Rocky Mountains Total	1,587.3	72	1,493.7	80
Midcontinent	630.8	28	373.9	20
Questar E&P Total	2,218.1	100	1,867.6	100

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Reserves – Cost-of-Service

Wexpro manages, develops and produces cost-of-service reserves for Questar Gas under the terms of the Wexpro Agreement. The following table sets forth estimated cost-of-service natural gas and oil reserves. The estimates of cost-of-service proved reserves were made by Wexpro reservoir engineers as of December 31, 2008. All reported reserves are located in the United States.

Estimated cost-of-service proved reserves
Natural gas (Bcf)	646.9
Oil (MMbbl)	4.5
Total proved reserves (Bcfe)	673.9
Proved developed reserves (Bcfe)	489.9

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, 2008, with the Energy Information Administration of the Department of Energy on Form EIA-23. Although the companies use the same technical and economic assumptions when they prepare the EIA-23, they are obligated to report reserves for all wells they operate, not for all wells in which they have an interest, and to include the reserves attributable to other owners in such wells.

Production

The following table sets forth the net production volumes, the average sales prices per Mcf of natural gas, per bbl of oil and NGL produced, and the lifting cost per Mcfe for the years ended December 31, 2008, 2007 and 2006. Lifting costs include labor, repairs, maintenance, materials, supplies and well workovers, administrative costs of production offices, insurance and property and severance taxes.

	Year Ended December 31,
	2008	2007	2006
Questar E&P
Volumes produced and sold
Natural gas (Bcf)	151.9	121.9	113.9
Oil and NGL (MMbbl)	3.3	3.0	2.6
Total production (Bcfe)	171.4	140.2	129.6
Average realized price, net to the well (including hedges)
Natural gas (Bcf)	$  7.56	$  6.45	$  5.98
Oil and NGL (MMbbl)	72.96	53.99	49.12
Lifting costs (per Mcfe)
Lease operating expense	$  0.73	$  0.63	$  0.57
Production taxes	0.61	0.43	0.45
Total lifting costs	$  1.34	$  1.06	$  1.02
Cost-of-Service
Volumes produced
Natural gas (Bcf)	46.1	34.9	38.8
Oil and NGL (MMbbl)	0.4	0.4	0.4
Total production (Bcfe)	48.6	37.4	40.9

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Productive Wells

The following table summarizes the Company’s productive wells (including cost-of-service wells) as of December 31, 2008. All of these wells are located in the United States.

	Gas	Oil	Total
Gross	5,468	1,007	6,475
Net	2,468	485	2,953

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 2008, the Company had 151 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, 2008. “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 Acres(1)		Undeveloped Acres(2)		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Arkansas	32,702	10,362	3,958	2,425	36,660	12,787
Colorado	150,868	102,931	165,060	76,928	315,928	179,859
Kansas	29,822	12,922	52,779	17,255	82,601	30,177
Louisiana	46,888	33,788	13,426	12,702	60,314	46,490
Montana	20,149	8,138	306,139	52,852	326,288	60,990
New Mexico	97,149	71,224	32,939	12,618	130,088	83,842
North Dakota	5,621	537	216,841	86,419	222,462	86,956
Oklahoma	1,559,034	279,707	158,626	91,869	1,717,660	371,576
South Dakota			204,398	107,151	204,398	107,151
Texas	130,989	43,926	68,414	52,655	199,403	96,581
Utah	141,497	109,115	235,955	136,961	377,452	246,076
Wyoming	284,446	178,058	320,384	219,135	604,830	397,193
Other	5,153	2,534	157,886	42,516	163,039	45,050
Total	2,504,318	853,242	1,936,805	911,486	4,441,123	1,764,728

⁽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:

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Leaseholds Expiring	Undeveloped Acres Expiring
	Gross	Net
12 months ending December 31,
2009	77,988	52,514
2010	78,763	44,200
2011	80,310	53,017
2012	76,084	74,825
2013 and later	187,987	171,648

Drilling Activity

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

	Year Ended December 31,
	Productive			Dry
	2008	2007	2006	2008	2007	2006
Net Wells Completed
Exploratory	2.3	0.3	0.9	0.9	0.4	5.2
Development	257.8	199.6	185.6	6.2	2.5	4.6
Gross Wells Completed
Exploratory	10	2	2	2	1	11
Development	490	426	408	13	11	18

MIDSTREAM FIELD SERVICES – Questar Gas Management

Gas Management owns 1,598 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 330 miles of gathering lines and associated field equipment, Field Services owns 75 miles of gathering lines and associated field equipment and Three Rivers owns 55 miles of gathering lines. Gas Management owns processing plants that have an aggregate capacity of 680 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 firm-capacity of 4,155 Mdth per day. These commitments include 1,948 Mdth per day for Questar Pipeline, 1,121 Mdth per day for Overthrust Pipeline, 81 Mdth per day for Southern Trails Pipeline and 1,005 Mdth per day for Questar Pipeline’s 50% ownership of White River Hub. Questar Pipeline’s transportation system includes 2,533 miles of natural gas transportation pipelines 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. Questar Pipeline’s 2,533 miles of natural gas transportation pipeline includes pipelines at storage fields and tap lines used to serve Questar Gas, 488 miles of the Southern Trails Pipeline, a wholly owned subsidiary, but does not include 165 miles of Southern Trails Pipeline t hat is not in service in southern California, and 214 miles of Overthrust Pipeline, a wholly owned subsidiary. Questar Pipeline’s system ranges in size from lines that are less than four inches in diameter to the 36-inch Overthrust Pipeline. 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.

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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 also owns gathering lines and processing facilities near Price, Utah, which provide gas-processing services for third parties.

RETAIL GAS DISTRIBUTION - Questar Gas

Questar Gas distributes gas to customers along the Wasatch Front, the major populated area of Utah, 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 25,819 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.

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. A liability is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. Disclosures are provided for contingencies reasonably likely to occur which would have a material adverse effect on the Company’s financial position, results of operations or cash flows. Some of the claims involve highly complex issues relating to liability, damages and other matters subject to substantial uncertainties and, therefore, the probability of liability or an estimate of loss cannot be reasonably determined.

Grynberg Case

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

Environmental Claims

In United States of America v. Questar Gas Management Co., Civil No. 208CV167, filed on February 29, 2008, in Utah Federal District Court, the Environmental Protection Agency (EPA) alleges that Gas Management violated the federal Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. EPA further alleges that the facilities are located within the original boundaries of the former Uncompahgre Indian Reservation and are therefore within “Indian Country”. EPA asserts primary CAA jurisdiction over "Indian Country" where state CAA programs do not apply. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for Gas Management’s facilities render them “major sources” of emissions for criteria and hazardous air pollutants. Categorization of the facilities as “major sources” affects the part icular regulatory program applicable to those facilities. EPA claims that Gas Management failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations for testing and reporting, among other things. Gas Management contends that its facilities have pollution controls installed that reduce their actual air emissions below major source thresholds, rendering them subject to different regulatory requirements. Gas Management intends to vigorously defend against the EPA’s claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying Utah’s CAA program or EPA's prior practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict the likely potential outcomes; however, management believes the company has accrued an appropriate liability for this c laim.

Regulatory Proceedings

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

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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 2008.

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 two peer groups of diversified natural gas companies selected by Questar, and of the S&P Composite-500 Stock Index. In 2008, the peer group was modified to better represent companies with operations similar to Questar.

	2003	2004	2005	2006	2007	2008
Questar	$100.00	$148.05	$223.08	$247.62	$325.88	$199.09
Prior peer group	100.00	137.26	186.71	225.75	291.53	221.93
Current peer group	100.00	140.08	180.13	216.84	275.66	141.12
S&P 500	100.00	110.87	116.31	134.66	142.05	89.51

The graph assumes $100 is invested at the close of trading on December 31, 2003, in the Company’s common stock, the indices of two sets of peer companies, and the S&P 500 Index. It also assumes all dividends are reinvested. For 2008, the company had a total return of -38.9% compared to -37.0% for the S&P 500 Index, -23.9% for the prior peer group and -48.8% for the current peer group. For the five-year period, the Company had a compound annual total return of 14.8% compared to -2.2% for the S&P 500 Index, 17.3% for the prior peer group and 7.1% for the current peer group. The prior peer group index was comprised of Energen Corporation, EQT Corporation, MDU Resources, National Fuel Gas Company, Oneok Inc. and Southwestern Energy Company. The current peer group is comprised of Energen Corporation, El Paso Corporation, EQT Corporation, National Fuel Gas Company, MDU Resources and Williams Companies, Inc.

The foregoing graph shall not be deemed to be filed as part of the Form 10-K and does not constitute soliciting material and should not be deemed filed or incorporated by reference into any other filing of Questar under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent the Company specifically incorporates the graph by reference.

Questar’s common stock is listed on the New York Stock Exchange under the symbol “STR.” 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. As of January 31, 2009, Questar had 9,212 shareholders of record. Following is a summary of Questar’s quarterly stock-price and dividend information:

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	High price	Low price	Dividend
		(per share)
2008
First quarter	$58.32	$45.00	$0.1225
Second quarter	71.64	56.17	0.1225
Third quarter	74.86	36.96	0.1225
Fourth quarter	$40.35	$20.66	0.1250
			$0.4925
2007
First quarter	$45.58	$37.98	$0.1175
Second quarter	55.84	44.61	0.1225
Third quarter	58.75	44.42	0.1225
Fourth quarter	$57.36	$50.67	0.1225
			$0.4850

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, 2008.

2008	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	14,772	$34.27	-	-
November	18,192	32.47	-	-
December	33,251	31.24	-	-
Total	66,215	$32.25	-	-

^(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,
	2008	2007	2006	2005	2004
	(in millions, except per-share amounts)
REVENUES	$3,465.1	$2,726.6	$2,835.6	$2,724.9	$1,901.4
OPERATING EXPENSES
Cost of natural gas and other products sold	1,007.6	917.1	1,223.6	1,371.3	821.8
Operating and maintenance	374.0	298.6	286.8	262.8	213.6
General and administrative	159.7	165.4	135.0	123.1	114.2
Production and other taxes	164.9	101.0	108.7	120.2	90.9
Depreciation, depletion and amortization	494.4	369.1	308.4	250.3	216.2
Other expenses	88.7	33.2	42.0	35.4	29.1
Total Operating Expenses	2,289.3	1,884.4	2,104.5	2,163.1	1,485.8
Net gain (loss) from asset sales	64.7	(0.9)	25.3	4.7	0.3
Operating income	1,240.5	841.3	756.4	566.5	415.9
Interest and other income	17.7	14.3	11.2	9.0	6.3

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Net mark to market gain (loss) on basis only swaps	(79.2)	5.7	(1.9)
Income from unconsolidated affiliates	2.3	8.9	7.5	7.5	5.1
Interest expense	(119.5)	(72.2)	(73.6)	(69.4)	(68.4)
Income taxes	(378.0)	(290.6)	(255.5)	(187.9)	(129.6)
Net Income	$  683.8	$  507.4	$  444.1	$  325.7	$  229.3
Earnings Per Common Share
Basic	$3.96	$2.95	$2.60	$1.92	$1.37
Diluted	$3.88	$2.88	$2.54	$1.87	$1.34
Weighted-Average Common Shares Outstanding
Used in basic calculation	172.8	172.0	170.9	169.6	167.5
Used in diluted calculation	176.1	175.9	175.2	174.3	171.4
Dividends Per Share	$0.4925	$0.485	$0.465	$0.445	$0.425
Book Value Per Common Share At December 31,	$19.69	$14.92	$12.83	$  9.08	$  8.53
Net Cash Provided From Operating Activities	$1,496.2	$1,141.0	$   965.0	$   695.8	$   585.7
Capital Expenditures	2,485.7	1,398.3	916.1	712.7	446.5
Total Assets At December 31,	$8,630.7	$5,944.2	$5,064.7	$4,374.3	$3,684.9
Capitalization At December 31,
Long-term debt, less current portion	2,078.9	$1,021.2	$1,022.4	$  983.2	$   933.2
Common equity	3,418.0	2,577.9	2,205.5	1,549.8	1,439.6
Total Capitalization	$5,496.9	$3,599.1	$3,227.9	$2,533.0	$2,372.8

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

RESULTS OF OPERATION

Following are comparisons of net income by line of business:

	Year Ended December 31,			Change
	2008	2007	2006	2008 vs. 2007	2007 vs. 2006
	(in millions, except per-share amounts)
Exploration and Production
Questar E&P	$408.0	$285.5	$253.9	$122.5	$31.6
Wexpro	73.9	59.2	50.0	14.7	9.2
Midstream Field Services – Gas Management	81.5	55.3	42.6	26.2	12.7
Energy Marketing – Energy Trading, and other	22.1	20.8	9.6	1.3	11.2
Market Resources Total	585.5	420.8	356.1	164.7	64.7
Interstate Gas Transportation – Questar Pipeline	58.0	45.0	45.4	13.0	(0.4)
Retail Gas Distribution – Questar Gas	40.2	37.4	37.0	2.8	0.4
Corporate	0.1	4.2	5.6	(4.1)	(1.4)
Net Income	$683.8	$507.4	$444.1	$176.4	$63.3
Earnings per share – diluted	$  3.88	$  2.88	$ 2.54	$  1.00	$0.34
Average diluted shares	176.1	175.9	175.2	0.2	0.7

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EXPLORATION AND PRODUCTION

Questar E&P

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

	Year Ended December 31,			Change
	2008	2007	2006	2008 vs. 2007	2007 vs. 2006
	(in millions)
Operating Income
REVENUES
Natural gas sales	$1,147.7	$786.9	$681.6	$360.8	$105.3
Oil and NGL sales	237.5	164.2	128.6	73.3	35.6
Other	6.9	4.9	5.5	2.0	(0.6)
Total Revenues	1,392.1	956.0	815.7	436.1	140.3
OPERATING EXPENSES
Operating and maintenance	125.4	87.9	73.6	37.5	14.3
General and administrative	55.8	56.3	42.4	(0.5)	13.9
Production and other taxes	104.0	60.1	58.3	43.9	1.8
Depreciation, depletion and amortization	330.9	243.5	185.7	87.4	57.8
Exploration	29.3	22.0	34.4	7.3	(12.4)
Abandonment and impairment	44.6	10.8	7.6	33.8	3.2
Natural gas purchases	0.5	2.2	2.8	(1.7)	(0.6)
Total Operating Expenses	690.5	482.8	404.8	207.7	78.0
Net gain (loss) from asset sales	60.4	(0.6)	24.3	61.0	(24.9)
Operating Income	$  762.0	$472.6	$435.2	$289.4	$  37.4
Operating Statistics
Production Volumes
Natural gas (Bcf)	151.9	121.9	113.9	30.0	8.0
Oil and NGL (MMbbl)	3.3	3.0	2.6	0.3	0.4
Total production (Bcfe)	171.4	140.2	129.6	31.2	10.6
Average daily production (MMcfe)	468.3	384.1	355.2	84.2	28.9
Average realized price, net to the well (including hedges)
Natural gas (per Mcf)	$   7.56	$   6.45	$   5.98	$  1.11	$   0.47
Oil and NGL (per bbl)	72.96	53.99	49.12	18.97	4.87

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

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

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

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

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

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

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

Net production in the Midcontinent grew 33% to 67.8 Bcfe in 2008, 16.8 Bcfe higher than 2007. Midcontinent production growth was driven by the first quarter 2008 acquisition of new natural gas development properties in northwest Louisiana, ongoing infill-development drilling in the Elm Grove field in northwest Louisiana, continued development of the Granite Wash/Atoka/Morrow play in the Texas Panhandle, and production from new outside-operated Woodford Shale horizontal gas wells in the Anadarko Basin in central Oklahoma.

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

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

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

Questar E&P production costs (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense, allocated-interest expense and production taxes) per Mcfe of production increased 17% to $3.94 per Mcfe in 2008 versus $3.38 per Mcfe in 2007. Questar E&P production costs are summarized in the following table:

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

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

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

In the third quarter of 2008, Questar E&P sold certain outside-operated producing properties and leaseholds in the Gulf Coast region of south Texas and recognized a pre-tax gain of approximately $61.2 million. These properties contributed 2.8 Bcfe to Questar E&P net production in 2008. In 2006, Questar E&P sold certain proved reserves and undeveloped leasehold interests in western Colorado and recognized a pre-tax gain of $22.7 million.

Major Questar E&P Operating Areas

Pinedale Anticline

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

In 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10-acre-density drilling for Lance Pool wells on about 12,700 acres of Market Resources 17,872-acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the currently estimated productive limits of Market Resources core acreage in the field. At December 31, 2008,

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

Uinta Basin

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

Rockies Legacy

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

Midcontinent

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

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

Wexpro

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

MIDSTREAM FIELD SERVICES – Questar Gas Management

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

	Year Ended December 31,			Change
	2008	2007	2006	2008 vs. 2007	2007 vs. 2006
	(in millions)
Operating Income
REVENUES
Gathering	$153.2	$111.4	$  89.2	$  41.8	$  22.2
Processing	137.0	94.9	94.7	42.1	0.2
Total Revenues	290.2	206.3	183.9	83.9	22.4

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

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

Total gathering margins (revenues minus direct gathering expenses) in 2008 increased 74% to $116.9 million compared to $67.1 million in 2007. Expanding Pinedale production, new projects serving third parties in the Uinta Basin and the consolidation of Rendezvous contributed to a 38% increase in third-party volumes in 2008. Gathering volumes increased 102.3 million MMBtu, or 35% to 392.5 million MMBtu in 2008. Rendezvous, formerly an unconsolidated affiliate, was consolidated with Gas Management beginning in 2008 and accounted for 39.0 million MMBtu. Rendezvous provides gas gathering services for the Pinedale and Jonah producing areas of Wyoming.

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

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

ENERGY MARKETING – Questar Energy Trading

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

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INTERSTATE GAS TRANSPORTATION – Questar Pipeline

Questar Pipeline reported 2008 net income of $58.0 million compared with $45.0 million in 2007 and $45.4 million in 2006. Operating income increased $21.9 million, or 24%, in 2008 compared to 2007 due primarily to transportation-system expansions that were placed in service in late 2007. Following is a summary of Questar Pipeline financial and operating results:

	Year Ended December 31,			Change
	2008	2007	2006	2008 vs. 2007	2007 vs. 2006
	(in millions)
Operating Income
REVENUES
Transportation	$172.4	$127.4	$119.9	$45.0	$  7.5
Storage	37.6	37.6	37.6
NGL sales	14.4	8.5	11.0	5.9	(2.5)
Energy services	15.3	16.0	16.1	(0.7)	(0.1)
Gas processing	4.6	8.7	6.3	(4.1)	2.4
Other	4.3	7.7	6.6	(3.4)	1.1
Total Revenues	248.6	205.9	197.5	42.7	8.4
OPERATING EXPENSES
Operating and maintenance	43.5	37.7	33.4	5.8	4.3
General and administrative	30.4	31.3	25.3	(0.9)	6.0
Depreciation and amortization	42.7	35.0	32.3	7.7	2.7
Impairment	14.0			14.0
Other taxes	7.8	7.3	7.3	0.5
Cost of goods sold	1.8	4.0	4.8	(2.2)	(0.8)
Total Operating Expenses	140.2	115.3	103.1	24.9	12.2
Net gain from asset sales	4.5	0.4	0.4	4.1
Operating Income	$112.9	$ 91.0	$ 94.8	$21.9	($3.8)
Operating Statistics
Natural gas-transportation volumes (MMdth)
For unaffiliated customers	608.1	352.3	320.4	255.8	31.9
For Questar Gas	120.9	113.8	116.7	7.1	(2.9)
For other affiliated customers	9.2	16.0	26.3	(6.8)	(10.3)
Total Transportation	738.2	482.1	463.4	256.1	18.7
Transportation revenue (per dth)	$0.23	$0.26	$0.26	($0.03)
Firm daily transportation demand at December 31,     (including White River Hub of 1,005 Mdth in     2008)	4,155	3,112	2,152	1,043	960
Natural gas processing
NGL sales (MMgal)	8.5	7.2	9.0	1.3	(1.8)
NGL sales price (per gal)	$1.70	$1.19	$1.22	$0.51	($0.03)

Revenues

Following is a summary of major changes in Questar Pipeline revenues for 2008 compared with 2007 and 2007 compared with 2006:

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29

	Change
	2008 vs. 2007	2007 vs. 2006
	(in millions)
Transportation
New transportation contracts	$51.0	$ 9.4
Expiration of transportation contracts	(8.5)	(1.7)
Other	2.5	(0.2)
NGL sales	5.9	(2.5)
Energy services	(0.7)	(0.1)
Gas processing	(4.1)	2.4
Other	(3.4)	1.1
Increase	$42.7	$ 8.4

As of December 31, 2008, Questar Pipeline had firm-transportation contracts of 4,155 Mdth per day, including 1,005 Mdth per day from Questar Pipeline’s 50% ownership of White River Hub, compared with 3,112 Mdth per day as of December 31, 2007. Questar Pipeline has expanded its transportation system in response to growing regional natural gas production and transportation demand. In November 2007, Questar Pipeline placed an expansion of its southern system in service. The southern system expansion increased Questar Pipeline’s 2008 firm-transport demand by 175 Mdth per day and revenues by $13.8 million compared to 2007. In December 2007, Questar Overthrust Pipeline placed the Wamsutter expansion project into service. The Wamsutter expansion increased Questar Overthrust Pipeline firm-transport demand by 750 Mdth per day and revenues by $31.2 million in 2008 compared to 2007.

Questar Gas is Questar Pipeline’s largest transportation customer with contracts for 901 Mdth per day. The majority of the 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 four to ten years and 100% of the firm-storage capacity at the aquifer facilities for terms extending for ten 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 earnings are driven primarily by demand revenues 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.

NGL sales were 69% higher in 2008 over 2007 due primarily to a 43% increase in NGL prices and an 18% increase in sales volume.

Expenses

Operating and maintenance expenses increased by 15% to $43.5 million in 2008 compared to $37.7 million in 2007 and $33.4 million in 2006 as a result of system expansions and higher labor and service costs. General and administrative expenses decreased 3% to $30.4 million in 2008 compared with $31.3 million in 2007 and $25.3 million in 2006. Operating, maintenance, general and administrative expenses per dth transported declined to $0.10 in 2008 compared with $0.14 in 2007 because transportation volumes increased 53%. Operating, maintenance, general and administrative expenses include processing and storage costs.

Depreciation expense increased 22% in 2008 compared to 2007 and increased 8% in 2007 compared to 2006 due to investment in pipeline expansions.

Sale of processing plant and gathering lines

Questar Transportation Services, a subsidiary of Questar Pipeline, sold a carbon dioxide processing plant and some associated gathering facilities in the second quarter of 2008. The net investment in these facilities was $20.0 million. The transaction closed in April 2008 and resulted in a pre-tax gain of $3.9 million.

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Impairment

Charges for asset impairment amounted to $14.0 million in 2008. Questar Pipeline impaired the entire $10.6 million investment in a potential salt cavern storage project located in southwestern Wyoming in the second quarter of 2008 based on a technical and economic evaluation of the project. In the fourth quarter of 2008, Questar Pipeline also took a $3.4 million pre-tax charge for impairment of certain costs associated with the California segment of its Southern Trails Pipeline.

RETAIL GAS DISTRIBUTION – Questar Gas

Questar Gas reported net income of $40.2 million in 2008 compared with $37.4 million in 2007 and $37.0 million in 2006. Operating income increased $8.1 million or 11% in 2008 compared with 2007 due primarily to higher revenues from new-customer growth and the outcome of a rate case that authorized higher recovery of in rates of certain costs. Following is a summary of Questar Gas financial and operating results:

	Year Ended December 31,			Change
	2008	2007	2006	2008 vs. 2007	2007 vs. 2006
	(in millions)
Operating Income
REVENUES
Residential and commercial sales	$926.7	$876.6	$ 988.4	$50.1	($111.8)
Industrial sales	12.0	9.9	23.5	2.1	(13.6)
Transportation for industrial customers	9.9	9.9	6.7		3.2
Service	5.6	5.9	7.1	(0.3)	(1.2)
Other	46.1	30.2	38.9	15.9	(8.7)
Total Revenues	1,000.3	932.5	1,064.6	67.8	(132.1)
Cost of natural gas sold	736.9	687.2	821.8	49.7	(134.6)
Margin	263.4	245.3	242.8	18.1	2.5
Other Operating Expenses
Operating and maintenance	87.1	73.4	73.2	13.7	0.2
General and administrative	38.7	45.5	41.9	(6.8)	3.6
Depreciation and amortization	41.5	38.8	40.9	2.7	(2.1)
Other taxes	11.9	11.5	11.6	0.4	(0.1)
Total Other Operating Expenses	179.2	169.2	167.6	10.0	1.6
Net (loss) from asset sales			(0.3)		0.3
Operating Income	$   84.2	$   76.1	$   74.9	$   8.1	$   1.2
OPERATING STATISTICS
Natural gas volumes (MMdth)
Residential and commercial sales	112.3	106.1	102.2	6.2	3.9
Industrial sales	1.7	1.6	3.1	0.1	(1.5)
Transportation for industrial customers	62.2	53.8	35.5	8.4	18.3
Total industrial	63.9	55.4	38.6	8.5	16.8
Total deliveries	176.2	161.5	140.8	14.7	20.7
Natural gas revenue (per dth)
Residential and commercial	$8.25	$8.26	$9.67	($0.01)	($1.41)
Industrial sales	6.99	6.18	7.64	0.81	(1.46)
Transportation for industrial customers	0.16	0.18	0.19	(0.02)	(0.01)
System natural gas cost (per dth)	$6.14	$ 5.93	$ 6.54	$0.21	($0.61)
Colder (warmer) than normal temperatures	8%	2%	(2%)	6%	4%
Temperature-adjusted usage per customer (dth)	109.9	110.8	113.6	(0.9)	(2.8)
Customers at December 31, (in thousands)	888.6	873.6	850.5	15.0	23.1

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Margin Analysis

Questar Gas’s margin (revenues less gas costs) increased $18.1 million in 2008 compared to 2007 and $2.5 million in 2007 compared to 2006. Following is a summary of major changes in Questar Gas’s margin for 2008 compared to 2007 and 2007 compared to 2006:

	Change
	2008 vs. 2007	2006 vs. 2007
	(in millions)
New customers	$3.9	$ 5.9
Conservation-enabling tariff	1.0	2.5
Change in usage per customer	(1.3)	(4.5)
Change in transportation revenues		3.2
Change in rates	4.1	(6.2)
Recovery of demand-side management costs	6.0	0.6
Recovery of gas-cost portion of bad-debt costs	2.9	(2.1)
Other, including shifting between rate classes	1.5	3.1
Increase	$18.1	$ 2.5

At December 31, 2008, Questar Gas served 888,602 customers, up from 873,607 at December 31, 2007. New-customer growth increased the margin by $3.9 million in 2008 and $5.9 million in 2007.

Temperature-adjusted usage per customer decreased 1% in 2008 compared with 2007 and 2% in 2007 compared to 2006. The impact on the company margin from changes in usage per customer has been mitigated by a pilot conservation-enabling tariff (CET) that was approved by the PSCU beginning 2006. The CET resulted in a margin increase of $1.0 million in 2008, largely offsetting the $1.3 million decrease in margin resulting from usage per customer. The CET resulted in a margin increase of $2.5 million in 2007, partially offsetting a $4.5 million decline in usage per customer.

Weather, as measured in degree days, was 8% colder than normal in 2008 and 2% colder than normal in 2007. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations.

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%. The company subsequently modified its request to $22.2 million to reflect a change in test year ordered by the PSCU and the impact of tax law changes on rate base. In the second quarter of 2008, Questar Gas received an order from the PSCU increasing rates by $12.0 million. The PSCU reduced Questar Gas’s allowed return on equity from 11.2% to 10%. The new rates went into effect in mid-August 2008 and increased the margin by $4.1 million in 2008.

Expenses

Cost of natural gas sold increased 7% in 2008 compared with 2007 due to a 6% increase in sales volumes and an increase in the cost of natural gas. Cost of natural gas sold decreased 16% in 2007 compared to 2006 primarily due to lower prices for purchased gas. 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, 2008, Questar Gas had a $45.8 million over-collected balance in the purchased-gas adjustment account representing costs recovered from customers in excess of costs incurred.

Operating and maintenance expenses increased $13.7 million or 19% in 2008 compared to 2007 due primarily to $3.9 million higher bad-debt costs, $5.9 million higher demand-side management costs and $1.4 million higher labor costs. Operating and maintenance expenses were unchanged in 2007 compared to 2006. General and administrative expenses decreased $6.8 million or 15% in 2008 compared to 2007 due to $3.5 million lower labor costs and $1.4 million lower legal costs. General and administrative expenses increased 9% in 2007 compared to 2006. The sum of operating, maintenance, general and administrative expenses per customer was $142 in 2008 compared to $136 in 2007 and $135 in 2006.

Depreciation expense increased 7% in 2008 compared to 2007 as a result of plant additions from customer growth and system expansion. Depreciation expense decreased 5% in 2007 compared to 2006 primarily as a result of reduced depreciation rates effective June 1, 2006, in accordance with a PSCU order.

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Consolidated Results below Operating Income

Interest and Other Income

Interest and other income increased $12.4 million or 87% in 2008 compared with 2007 and 28% in 2007 compared with 2006. The details of interest and other income for 2008, 2007 and 2006 are shown in the table below:

	Year Ended December 31,			Change
	2008	2007	2006	2008 vs. 2007	2007 vs. 2006
	(in millions)
Interest income and other earnings	$  2.2	$5.0	$ 5.4	($ 2.8)	($0.4)
Inventory sales	10.6	0.6	0.7	10.0	(0.1)
Allowance for other funds used during
construction (capitalized finance costs)	4.1	2.0	1.0	2.1	1.0
Return earned on working-gas inventory and
purchased-gas-adjustment account	5.0	5.5	5.9	(0.5)	(0.4)
Southern Trails option expiration	3.0			3.0
Collection of a note receivable	2.8			2.8
Hedge ineffectiveness	(1.0)	1.2	(0.1)	(2.2)	1.3
Loss on early extinguishment of debt			(1.7)		1.7
Total	$26.7	$14.3	$11.2	$12.4	$3.1

Income from unconsolidated affiliates

Income from unconsolidated affiliates was $2.3 million in 2008 compared to $8.9 million in 2007 and $7.5 million in 2006. Rendezvous Gas Services, which accounted for the majority of income from unconsolidated affiliates in 2007 and 2006, was consolidated beginning in 2008.

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

The Company uses basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials that may result from capacity constraints on regional gas pipelines. The Company recognized a pre-tax net mark-to-market loss of $79.2 million on natural gas basis-only swaps in 2008 compared to a $5.7 million pre-tax gain in 2007 and a $1.9 million pre-tax loss in 2006.

Interest expense

Interest expense rose 66% in 2008 compared to 2007 due primarily to financing activities associated with the purchase of natural gas development properties in northwest Louisiana and pipeline expansions. Interest rates on the Company’s commercial-paper borrowings spiked in September 2008 and later retreated reflecting increased liquidity pressures and turmoil generally experienced by financial markets. The Company maintains committed credit lines with banks to provide liquidity when commercial-paper markets are illiquid. Interest expense declined 2% in 2007 compared to 2006. Capitalized interest charges on construction projects amounted to $6.1 million in 2008 compared to $8.0 million in 2007 and $0.8 million in 2006.

Income taxes

The effective combined federal and state income tax rate was 35.6% in 2008 compared with 36.4% in 2007 and 36.5% in 2006.

LIQUIDITY AND CAPITAL RESOURCES

Operating Activities

Net cash provided from operating activities increased 31% in 2008 compared to 2007 and 18% in 2007 compared to 2006 due to higher net income and noncash adjustments to net income. Noncash adjustments to net income consisted primarily of depreciation, depletion and amortization, and deferred income taxes. Cash sources from operating assets and liabilities were lower in 2008 primarily due to changes in the values of inventories and receivables. Receivables increased because of higher natural gas prices for gas distribution. Net cash provided from operating activities is presented below:

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	Year Ended December 31,			Change
	2008	2007	2006	2008 vs. 2007	2007 vs. 2006
	(in millions)
Net income	$  683.8	$507.4	$444.1	$176.4	$  63.3
Noncash adjustments to net income	984.7	599.1	438.4	385.6	160.7
Changes in operating assets and liabilities	(172.3)	34.5	82.5	(206.8)	(48.0)
Net cash provided from operating activities	$1,496.2	$1,141.0	$965.0	$355.2	$176.0

Investing Activities

Capital spending in 2008 amounted to $2,485.7 million. The details of capital expenditures in 2008 and 2007 and a forecast for 2009 are shown in the table below:

	Year Ended December 31,
	2009 Forecast	2008	2007
	(in millions)
Questar Market Resources
Drilling and other exploration	$790.1	$1,136.4	$678.7
Reserve acquisitions		727.8	46.1
Wexpro development drilling	114.5	144.8	109.4
Midstream field services	149.1	394.5	128.1
Energy Trading and other	40.2	1.6	2.0
Capital expenditure accruals		(124.6)	(20.4)
	1,093.9	2,280.5	943.9
Questar Pipeline
Transportation and storage	100.9	90.7	321.7
Capital expenditure accruals		(12.4)	(3.2)
	100.9	78.3	318.5
Questar Gas
Retail distribution system and customer additions	83.6	122.2	129.9
Capital expenditure accruals		4.1	6.0
	83.6	126.3	135.9
Other	0.2	0.6
Total capital expenditures	$1,278.6	$2,485.7	$1,398.3

Questar E&P

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

Questar Gas Management

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

Questar Pipeline

During 2008, Questar Pipeline invested in the White River Hub in Colorado and expanded compression facilities.

Questar Gas

During 2008, Questar Gas added 446 miles of main, feeder and service lines to provide service to 14,995 additional customers and replaced high-pressure feeder lines.

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Financing Activities

In 2008, net cash used in investing activities of $2,358.7 million exceeded net cash flow from operating activities by $862.5 million. The $862.5 million difference resulted primarily from the February 2008 acquisition of natural gas development properties in northwest Louisiana and expanded drilling activities. Long-term debt increased by $990.4 million net and short-term debt decreased by $29.5 million in 2008. In 2007, net cash used in investing activities exceeded net cash provided from operating activities by $244.1 million. The Company funded this shortfall with increased short-term and long-term debt.

Questar sells commercial paper that is rated A2 by Standard & Poor’s and P2 by Moody’s to meet short-term financing requirements. The Company maintains committed credit lines with banks to provide liquidity when commercial-paper markets are illiquid. Turmoil in the global-credit markets has severely reduced liquidity, making borrowing terms less attractive. At times the Company has used back-up lines of credit with banks instead of commercial paper to meet short-term funding needs.

Short-term debt amounted to $231.1 million at December 31, 2008 and included $151.1 million of commercial paper with an average interest rate of 4.59% and $80.0 million of short-term bank borrowings with an average interest rate of 2.34%. The balance of short-term debt was $260.6 million at December 31, 2007, and was comprised of commercial paper with an average interest rate of 5.7%. Questar’s commercial paper borrowings are backed by short-term line-of-credit arrangements. At December 31, 2008, the Company had $285.0 million of short-term lines of credit available under its total committed credit lines of $365.0 million.

In January 2008, Questar Pipeline sold $200.0 million of 10-year notes with a 5.83% interest rate and used the proceeds to repay maturing long-term debt and short-term intercompany debt. In March 2008, Questar Gas sold $50.0 million of 10-year notes with a 6.3% interest rate and $100.0 million of 30-year notes with a 7.2% interest rate. Proceeds from the Questar Gas borrowings were used to repay maturing long-term debt and short-term intercompany debt.

In March 2008, Market Resources entered into a new $800.0 million five-year revolving-credit facility with multiple bank counterparties. In April 2008, Market Resources sold $450.0 million of 10-year notes with a 6.8% interest rate. Proceeds from the sale of the notes and funds available under the revolving-credit facility were used to repay short-term bank debt.

Questar’s consolidated capital structure consisted of 41% combined short- and long-term debt and 59% common shareholders’ equity at December 31, 2008, compared to 35% combined short- and long-term debt and 65% common shareholders’ equity a year earlier. At December 31, 2008, Market Resources had unused capacity of $350.0 million on the five-year revolving-credit facility with banks.

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

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

	Moody’s	Standard & Poor’s
Market Resources	Baa3	BBB+
Questar Pipeline	A2	BBB+
Questar Gas	A2	BBB+
Questar commercial paper	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, 2008:

	Payments Due by Year
	Total	2009	2010	2011	2012	2013	After 2014
	(in millions)
Fixed-rate long-term debt	$2,122.2	$  42.0		$332.0	$91.5	$492.0	$1,164.7
Interest on fixed-rate long-term debt	891.4	108.7	$106.2	91.3	80.7	74.6	429.9

QUESTAR 2008 FORM 10-K

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Gas-purchase contracts	513.4	88.6	44.2	31.1	27.8	27.8	293.9
Drilling contracts	182.7	109.5	49.1	20.9	3.2
Transportation contracts	103.4	12.9	12.9	12.6	10.7	8.7	45.6
Operating leases	33.2	7.2	7.5	7.6	5.7	3.0	2.2
Total	$3,846.3	$368.9	$219.9	$495.5	$219.6	$606.1	$1,936.3

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

Critical Accounting Policies, Estimates and Assumptions

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 2008, revisions of reserve estimates, other than revisions related to Pinedale increased-density, resulted in a 152.9 Bcfe decrease in Questar E&P’s proved reserves and a 20.2 Bcfe decrease in cost-of-service proved reserves. Revisions associated with Pinedale increased-density drilling added 161.8 Bcfe to Questar E&P’s estimated prov ed reserves at December 31, 2008, and 68.2 Bcfe of additional cost-of-service proved reserves. See Note 16 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company’s estimated proved reserves.

Successful Efforts Accounting for Gas and Oil Operations

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

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

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

Questar 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.

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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 defined-benefit pension and life insurance plans covering a majority of its employees and a postretirement medical plan providing coverage to less than half 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.

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 formulates 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, 2008 and 2007. A 0.5% decrease in the discount rate would increase the Company’s 2009 estimated annual pension expense by about $3.5 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 for purposes of paying pension benefits. 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 historical and forecasted rates of

QUESTAR 2008 FORM 10-K

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return on these types of securities. The expected long-term rate of return determined by the Company was 8.00% as of January 1, 2008 and 2007. 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 2009 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 and a portion of Energy Trading gas- and oil-marketing transactions

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

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

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

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

Market Resources uses natural gas basis-only swaps to manage the risk of widening-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 the Market Resources derivative positions for equity production as of December 31, 2008, is shown below:

QUESTAR 2008 FORM 10-K

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	Rocky			Rocky
Time Periods	Mountains	Midcontinent	Total	Mountains	Midcontinent	Total
				Estimated
	Gas (Bcf) Fixed-price Swaps			Average price per Mcf, net to the well
2009
First half	34.5	29.5	64.0	$7.24	$8.12	$7.65
Second half	35.0	30.0	65.0	7.24	8.12	7.65
12 months	69.5	59.5	129.0	7.24	8.12	7.65
2010
First half	6.7	26.2	32.9	$6.88	$8.09	$7.84
Second half	6.8	26.6	33.4	6.88	8.09	7.84
12 months	13.5	52.8	66.3	6.88	8.09	7.84
				Estimated
	Gas (Bcf) Basis-only Swaps			Average basis per Mcf, net to the well
2009
First half	9.3	3.3	12.6	$2.94	$1.22	$2.49
Second half	9.4	3.4	12.8	2.94	1.22	2.49
12 months	18.7	6.7	25.4	2.94	1.22	2.49
2010
First half	30.2	6.6	36.8	$3.39	$0.95	$2.95
Second half	30.7	6.8	37.5	3.39	0.95	2.95
12 months	60.9	13.4	74.3	3.39	0.95	2.95
2011
First half	45.3	6.9	52.2	$2.29	$0.79	$2.09
Second half	46.1	6.9	53.0	2.29	0.79	2.09
12 months	91.4	13.8	105.2	2.29	0.79	2.09
				Estimated
	Oil (Mbbl) Fixed-price Swaps			Average price per bbl, net to the well
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, 2008, Market Resources held commodity-price hedging contracts covering about 234.4 million MMBtu of natural gas, 0.7 million barrels of oil and basis-only swaps on an additional 204.9 Bcf of natural gas. A year earlier Market Resources hedging contracts covered 245.0 million MMBtu of natural gas, 2.0 million barrels of oil, 5.0 million gallons of NGL and natural gas basis-only swaps on an additional 40.8 Bcf. Changes in the fair value of derivative contracts from December 31, 2007 to December 31, 2008, are presented below:

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	Fixed-price	Basis-only
	Swaps	Swaps	Total
	(in millions)
Net fair value of gas- and oil-derivative contracts   outstanding at Dec. 31, 2007	$   50.7	$  3.8	$   54.5
Contracts realized or otherwise settled	(7.5)	(0.2)	(7.7)
Change in gas and oil prices on futures markets	241.0	2.4	243.4
Contracts added	273.6	(95.7)	177.9
Contracts redesignated as fixed-price swaps	(14.2)	14.2
Net Fair Value Of Gas- and Oil-Derivative Contracts   Outstanding at Dec. 31, 2008	$543.6	($75.5)	$468.1

A table of the net fair value of gas- and oil-derivative contracts as of December 31, 2008, is shown below. About 92% of the 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	Basis-only
	Swaps	Swaps	Total
	(in millions)
Contracts maturing by Dec. 31, 2009	$431.2	($0.4)	$430.8
Contracts maturing between Jan. 1, 2010 and Dec. 31, 2010	112.4	(60.4)	52.0
Contracts maturing between Jan. 1, 2011 and Dec. 31, 2011		(14.7)	(14.7)
Net Fair Value Of Gas- and Oil-Derivative Contracts   Outstanding at Dec. 31, 2008	$543.6	($75.5)	$468.1

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,
	2008	2007
	(in millions)
Net fair value – asset (liability)	$468.1	$  54.5
Value if market prices of gas and oil and basis differentials decline by 10%	590.4	217.7
Value if market prices of gas and oil and basis differentials increase by 10%	345.9	(108.8)

Credit Risk

Market Resources requests credit support and, in some cases, prepayment from companies with unacceptable credit risks. Market Resources five largest customers are Sempra Energy Trading Corp., Enterprise Products Operating, Chevron USA Inc., Occidental Energy Marketing Inc. and Nevada Power Company. Sales to these companies accounted for 20% of Market Resources revenues before elimination of intercompany transactions in 2008, and their accounts were current at December 31, 2008.

Questar Pipeline requests credit support, such as letters of credit and cash deposits, from companies that pose unfavorable credit risks. All companies posing such concerns were current on their accounts at December 31, 2008. Questar Pipeline’s largest customers include Questar Gas, Rockies Express Pipeline, EOG Resources, XTO Energy and PacifiCorp.

Questar Gas requires deposits from customers that pose unfavorable credit risks. No single customer accounted for a significant portion of revenue in 2008.

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Interest-Rate Risk

The fair value of fixed-rate debt is subject to change as interest rates fluctuate. The Company’s ability to borrow and the rates quoted by lenders have been adversely affected by the illiquid credit markets as described in Item 1A. Risk Factors of Part I of this Annual Report on Form 10-K. The Company had $2,122.2 million of fixed-rate long-term debt with a fair value of $1,994.8 million at December 31, 2008. A year earlier the Company had $1,123.5 million of fixed-rate long-term debt with a fair value of $1,139.1 million. If interest rates had declined 10%, fair value would increase to $2,061.4 million in 2008 and $1,164.4 million in 2007. 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:

41

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

42

Consolidated Balance Sheets at December 31, 2008 and 2007

43

Consolidated Statements of Common Shareholders’ Equity, three years ended

December 31, 2008

45

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

46

47

Financial Statement Schedules:

Valuation and Qualifying Accounts, for the three years ended December 31, 2008

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, 2008 and 2007, 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, 2008. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the financial statements, Questar Corporation adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, effective January 1, 2007.

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, 2008, 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 24, 2009 expressed an unqualified opinion thereon.

/s/Ernst & Young LLP

Salt Lake City, Utah

February 24, 2009

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QUESTAR CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
	Year Ended December 31,
	2008		2007		2006
	(in millions, except per share amounts)
REVENUES
Market Resources	$2,297.2	$1,671.3		$1,659.4
Questar Pipeline	173.7	127.7		117.1
Questar Gas	994.2	927.6		1,059.1
Total Revenues	3,465.1	2,726.6		2,835.6
OPERATING EXPENSES
Cost of natural gas and other products sold (excluding operating     expenses shown separately)	1,007.6	917.1		1,223.6
Operating and maintenance	374.0	298.6		286.8
General and administrative	159.7	165.4		135.0
Production and other taxes	164.9	101.0		108.7
Depreciation, depletion and amortization	494.4	369.1		308.4
Exploration	29.3	22.0		34.4
Abandonment and impairment	59.4	11.2		7.6
Total Operating Expenses	2,289.3	1,884.4		2,104.5
Net gain (loss) from asset sales	64.7	(0.9)		25.3
OPERATING INCOME	1,240.5	841.3		756.4
Interest and other income	26.7	14.3		11.2
Minority interest	(9.0)
Income from unconsolidated affiliates	2.3	8.9		7.5
Net mark-to-market gain (loss) on basis-only swaps	(79.2)	5.7		(1.9)
Interest expense	(119.5)	(72.2)		(73.6)
INCOME BEFORE INCOME TAXES	1,061.8	798.0		699.6
Income taxes	378.0	290.6		255.5
NET INCOME	$  683.8	$   507.4		$   444.1
EARNINGS PER COMMON SHARE
Basic	$3.96	$2.95		$2.60
Diluted	3.88	2.88		2.54
Weighted average common shares outstanding
Used in basic calculation	172.8	172.0		170.9
Used in diluted calculation	176.1	175.9		175.2

See notes accompanying the consolidated financial statements

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QUESTAR CORPORATION
CONSOLIDATED BALANCE SHEETS
	December 31,
	2008	2007
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$     23.9	$      14.2
Federal income taxes recoverable	24.2	6.6
Accounts receivable, net	362.4	333.0
Unbilled gas accounts receivable	95.8	78.2
Fair value of derivative contracts	431.3	78.1
Inventories, at lower of average cost or market
Gas and oil storage	85.5	66.1
Materials and supplies	106.9	48.9
Regulatory assets	20.6	9.4
Prepaid expenses and other	34.4	24.4
Total Current Assets	1,185.0	658.9
Net Property, Plant and Equipment – successful
efforts method of accounting for gas and oil properties	7,133.0	5,098.6
Investment in Unconsolidated Affiliates	68.4	52.8
Other Assets
Goodwill	70.0	70.7
Regulatory assets	26.3	28.4
Fair value of derivative contracts	106.3	7.8
Other noncurrent assets, net	41.7	27.0
Total Other Assets	244.3	133.9
Total Assets	$8,630.7	$5,944.2

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QUESTAR CORPORATION
	December 31,
	2008	2007
	(in millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term debt	$    231.1	$   260.6
Accounts payable and accrued expenses
Accounts and other payables	561.6	463.1
Production and other taxes	57.2	52.1
Customer credit balances	34.9	34.1
Interest	27.9	15.2
Total accounts payable and accrued expenses	681.6	564.5
Fair value of derivative contracts	0.5	9.3
Purchased-gas adjustment	45.8	58.1
Deferred income taxes - current	130.6	4.9
Current portion of long-term debt	42.0	101.3
Total Current Liabilities	1,131.6	998.7
Long-term debt, less current portion	2,078.9	1,021.2
Deferred income taxes	1,334.1	942.4
Asset retirement obligations	175.6	149.1
Pension benefits	205.2	73.3
Postretirement benefits	44.8	30.2
Fair value of derivative contracts	69.0	22.1
Other long-term liabilities	144.0	129.3
Commitments and contingencies – Note 11
Minority interest	29.5
COMMON SHAREHOLDERS’ EQUITY
Common stock – without par value; 350.0 shares authorized;
173.6 outstanding at December 31, 2008, and 172.8 outstanding at December 31, 2007	451.0	429.3
Retained earnings	2,772.3	2,173.9
Accumulated other comprehensive income (loss)	194.7	(25.3)
Total Common Shareholders’ Equity	3,418.0	2,577.9
Total Liabilities and Common Shareholders’ Equity	$8,630.7	$5,944.2

See notes accompanying the consolidated financial statements

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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, 2006	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)
Common stock issued	1.1	7.1
Common stock repurchased	(0.3)	(15.3)
2008 net income				683.8				$683.8
Dividends paid ($0.4925 per share)				(85.4)
Share-based compensation		16.7
Tax benefit from share-based compensation		13.2
Other comprehensive income
Change in unrealized fair value of derivatives					494.0			494.0
Change in unrecognized actuarial gain					(132.8)			(132.8)
Change in unrecognized prior-service costs					(13.9)			(13.9)
Income taxes					(127.3)			(127.3)
Total comprehensive income								$903.8
Balances at December 31, 2008	173.6	$451.0		$2,772.3	$194.7

See notes accompanying the consolidated financial statements

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QUESTAR CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Year Ended December 31,
	2008	2007	2006
	(in millions)
OPERATING ACTIVITIES
Net income	$   683.8	$   507.4	$   444.1
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	502.1	375.8	316.1
Deferred income taxes	377.1	191.2	100.7
Abandonment and impairment	59.4	11.2	7.6
Share-based compensation	16.7	12.9	9.7
Dry exploratory well expenses	9.7	12.3	26.3
Net (gain) loss from asset sales	(64.7)	0.9	(25.3)
Income from unconsolidated affiliates	(2.3)	(8.9)	(7.5)
Distributions from unconsolidated affiliates	0.5	10.4	7.1
Net mark-to-market (gain) loss on basis-only swaps	79.2	(5.7)	1.9
Minority interest	9.0
Other	(2.0)	(1.0)	1.8
Changes in operating assets and liabilities
Accounts receivable	(47.0)	(7.6)	61.8
Inventories	(77.4)	26.7	(8.0)
Prepaid expenses	(10.0)	3.3	2.4
Accounts payable and accrued expenses	(7.4)	(13.6)	(72.2)
Federal income taxes	(17.6)	3.4	1.3
Purchased-gas adjustments	(12.3)	16.2	81.7
Other	(0.6)	6.1	15.5
NET CASH PROVIDED FROM OPERATING ACTIVITIES	1,496.2	1,141.0	965.0
INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(2,427.5)	(1,371.2)	(883.5)
Dry exploratory well expenses	(9.7)	(12.3)	(26.3)
Other investments	(48.5)	(14.8)	(6.3)
Total capital expenditures	(2,485.7)	(1,398.3)	(916.1)
Cash used in disposition of assets	(3.7)	(1.3)	(0.7)
Proceeds from disposition of assets	130.7	14.5	35.3
NET CASH USED IN INVESTING ACTIVITIES	(2,358.7)	(1,385.1)	(881.5)
FINANCING ACTIVITIES
Common stock issued	7.1	5.9	10.8
Common stock repurchased	(15.3)	(10.2)	(6.2)
Long-term debt issued, net of issue costs	1,741.7	100.0	247.0
Long-term debt repaid	(751.3)	(10.0)	(200.0)
Change in short-term debt	(29.5)	220.6	(54.5)

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Dividends paid	(85.4)	(83.7)	(79.7)
Excess tax benefits from share-based compensation	13.2	11.1	12.0
Distribution to minority interest	(9.3)
Other	1.0		(1.7)
NET CASH PROVIDED FROM (USED IN) FINANCING ACTIVITIES	872.2	233.7	(72.3)
Change in cash and cash equivalents	9.7	(10.4)	11.2
Beginning cash and cash equivalents	14.2	24.6	13.4
Ending cash and cash equivalents	$   23.9	$    14.2	$   24.6
Supplemental Disclosure of Cash Paid During the Year for:
Interest	$109.8	$   77.3	$   70.4
Income taxes	13.8	89.5	144.1

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. Rendezvous Gas Services, an affiliate, was consolidated beginning in 2008 as a result of a step acquisition caused by disproportionate ownership. All significant intercompany accounts and transactions have been eliminated in consolidation.

Investment in Unconsolidated Affiliates

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 is included in the determination of net income.

The principal unconsolidated affiliates and the Company’s ownership percentage as of December 31, 2008, were White River Hub, LLC, a limited liability corporation (50%) engaged in interstate natural gas transportation and Uintah Basin Field Services, LLC, (38%) and Three Rivers Gathering, LLC, (50%) both limited liability corporations 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, was $3.1 million in 2008 and $2.7 million in 2007.

Energy Trading reports revenues on a gross basis because, in the judgment of management, the nature and circumstances of its marketing transactions are consistent with guidance for gross revenue reporting. 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 8 for a description and comparison of regulatory assets and liabilities as of December 31, 2008 and 2007.

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 Capitalized costs of unproved properties are reclassified as proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.

Capitalized exploratory well costs

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

Cost-of-service gas and oil operations

The successful efforts method of accounting is used for “cost-of-service” reserves managed, developed and produced by Wexpro for gas utility affiliate Questar Gas. Cost-of-service reserves are properties for which the operations and return on investment are subject to the Wexpro Agreement (see Note 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 including a return on Wexpro’s investment. Wexpro sells crude-oil production from certain oil-producing properties at market prices with the revenues used to recover operating expenses and to provide Wexpro a return on its investment. Any operating income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%. Amounts received by Questar Gas from the sharing of Wexpro’s oil income are used to reduce natural-gas costs t o utility customers.

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

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

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,
	2008	2007	2006
Questar Pipeline transportation, storage and other energy services	3.7%	3.4%	3.5%
Questar Gas distribution plant	3.0%	3.1%	3.4%

Impairment of Long-Lived Assets

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

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

Goodwill and Other Intangible Assets

Goodwill represents the excess of the amount paid 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, which is recorded in interest and other income. AFUDC on equity funds amounted to $4.1 million in 2008, $2.0 million in 2007 and $1.0 million in 2006 and increased interest and other income in the Consolidated Statements of Income. Interest expense was reduced by $6.1 million in 2008, $8.0 million in 2007 and $0.8 million in 2006.

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

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

·

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

·

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

·

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

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

Basis-Only Swaps

Basis-only swaps are used to manage the risk of widening basis differentials. These contracts are marked to market monthly with any change in the valuation recognized in the determination of 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 $7.0 million in 2008, $2.6 million in 2007 and $6.1 million in 2006. The allowance for bad-debt expenses was $8.5 million at December 31, 2008 and $6.0 million at December 31, 2007. 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.

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In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). The interpretation applies to all tax positions related to income taxes subject to SFAS 109 “Accounting for Income Taxes.” FIN 48 provides guidance for the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Questar adopted the provisions of FIN 48 effective January 1, 2007. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company’s recorded income tax benefits will be fully realized. There were no unrecognized tax benefits at the beginning or at the end of the twelve-month periods ended December 31, 2008 and 2007. Income tax returns for 2005 and subsequent years are subject to examination. As of the date of adoption, there were no amounts accrued for penalties or interest related to unrecognized tax benefits.

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. See Note 3 for further discussion on share-based compensation.

Comprehensive Income

Comprehensive income is the sum of net income as reported in the Consolidated Statements of Income and other comprehensive income or loss reported in the Consolidated Statements 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,
	2008	2007
	(in millions)
Unrealized gain on derivatives	$341.6	$ 31.0
Pension liability	(129.5)	(47.5)
Postretirement benefits liability	(17.4)	(8.8)
Accumulated other comprehensive income (loss)	$194.7	($25.3)

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

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	Year Ended December 31,
	2008	2007	2006
	(in millions)
Unrealized gain on derivatives	($183.4)	$59.0	($198.7)
Pension liability	50.8	(13.2)	29.4
Postretirement benefits liability	5.3	(2.9)	8.4
	($127.3)	$42.9	($160.9)

Business Segments

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

Recent Accounting Developments

SFAS 141(R) “Business Combinations”

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

SFAS 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, is applied prospectively to all noncontrolling interests including any that arose before the effective date.

SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities”

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

SEC “Modernization of Oil and Gas Reporting Requirements”

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

Reclassifications

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

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

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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,
	2008	2007	2006
	(in millions)
Weighted-average basic common shares outstanding	172.8	172.0	170.9
Potential number of shares issuable under the LTSIP	3.3	3.9	4.3
Average diluted common shares outstanding	176.1	175.9	175.2

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 2008, 2007 and 2006 distributions. At December 31, 2008, 1,774,477, 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 three or four equal, annual installments.. 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 vest 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.

Note 3 – Share-Based Compensation

Questar issues stock options and restricted shares to certain officers, employees and non-employee directors under its LTSIP and recognizes expense over time as the stock options or restricted shares vest. Questar uses an accelerated method in recognizing share-based compensation costs with graded-vesting periods. Share-based compensation expense amounted to $16.7 million in 2008 compared with $12.9 million in 2007 and $9.7 million in 2006. Deferred share-based compensation, representing the nonvested value of restricted share awards, amounted to $17.7 million at December 31, 2008 and $14.0 million at December 31, 2007. Deferred share-based compensation is included in common stock on the Consolidated Balance Sheets. Cash flow from income tax benefits in excess of recognized compensation expense amounted to $13.2 million in 2008, $11.1 million in 2007 and $12.0 million in 2006. There were 9,571,679 shares available for future grant at December 31, 2008.

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

	October 2008	February 2008	February 2007
Fair value of options at grant date	$28.58	$53.83	$41.08
Risk-free interest rate	3.20%	2.72%	4.77%
Expected price volatility	32.3%	20.3%	22.4%
Expected dividend yield	1.72%	0.91%	1.14%
Expected life in years	5.0	5.0	5.2

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Unvested stock options increased by 292,500 shares to 857,500 in 2008. Stock-option transactions under the terms of the LTSIP for the three years ended December 31, 2008, are summarized below:

	Options Outstanding	Price Range	Weighted Average Price
Balance at January 1, 2006	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
Granted	317,500	28.58 - 53.83	30.97
Exercised	(763,026)	7.50 – 17.55	10.33
Balance at December 31, 2008	4,183,075	$7.50 - $53.83	$17.53

Options Outstanding				Options Exercisable		Unvested Options
Range of exercise prices	Number outstanding at Dec. 31, 2008	Weighted-average remaining term in years	Weighted-average exercise price	Number exercisable at Dec. 31, 2008	Weighted-average exercise price	Number unvested at Dec. 31, 2008	Weighted- average exercise price
$ 7.50 – $ 8.50	423,194	1.0	$  7.62	423,194	$  7.62
11.48 – 11.98	856,988	3.1	11.58	856,988	11.58
13.56 – 14.86	1,931,119	3.5	13.71	1,931,119	13.71
17.55 – 24.33	114,274	6.0	23.48	114,274	23.48
28.58 – 53.83	857,500	3.9	36.16			857,500	$36.16
	4,183,075	3.3	$17.53	3,325,575	$12.72	857,500	$36.16

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

	Restricted Shares		Weighted Average
	Outstanding	Price Range	Price
Balance at January 1, 2006	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
Granted	359,965	25.12 -   70.13	53.91
Forfeited	(26,916)	25.50 -   70.13	47.30
Distributed	(305,973)	13.55 -   56.65	31.78
Balance at December 31, 2008	856,000	$24.33 – $70.13	$45.64

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Note 4 – Property, Plant and Equipment

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

	December 31,
	2008	2007
	(in millions)
Property, plant and equipment
Market Resources
Questar E&P
Proved properties	$4,912.6	$3,306.9
Unproved properties, not being depleted	193.2	55.6
Support equipment and facilities	35.6	23.3
Questar E&P total	5,141.4	3,385.8
Wexpro	911.5	766.1
Gas Management	976.6	516.5
Energy Trading and other	41.3	39.9
Market Resources total	7,070.8	4,708.3
Questar Pipeline	1,507.7	1,490.5
Questar Gas	1,646.8	1,539.2
Corporate	4.5	3.9
	$10,229.8	$7,741.9
Accumulated depreciation, depletion and amortization
Market Resources
Questar E&P	$1,421.8	$1,114.3
Wexpro	374.9	331.4
Gas Management	159.3	115.3
Energy Trading and other	8.4	6.7
Market Resources total	1,964.4	1,567.7
Questar Pipeline	471.4	441.9
Questar Gas	657.3	630.3
Corporate	3.7	3.4
	3,096.8	2,643.3
Net Property, Plant and Equipment	$7,133.0	$5,098.6

Questar E&P proved and unproved leaseholds had a net book value at December 31 of $1,074.2 million in 2008 and $381.1 million in 2007.

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

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

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

Questar Pipeline impairment expense amounted to $14.0 million in 2008. Questar Pipeline impaired the entire $10.6 million investment in a potential salt cavern storage project located in southwestern Wyoming in the second quarter of 2008 based on a technical and economic evaluation of the project. In the fourth quarter of 2008, Questar Pipeline also took a $3.4 million pre-tax charge for impairment of certain costs associated with the California segment of its Southern Trails Pipeline.

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:

	2008	2007
	(in millions)
ARO liability at January 1,	$149.1	$132.4
Accretion	9.7	8.3
Liabilities incurred	17.5	8.9
Revisions	1.5	1.0
Liabilities settled	(2.2)	(1.5)
ARO liability at December 31,	$175.6	$149.1

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, 2008, approximately $9.9 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 presented in the table below and exclude amounts that were capitalized and subsequently expensed in the period. All of these costs have been capitalized for less than one year.

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

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Note 7 – Fair-Value Measures, Financial Instruments and Risk Management

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

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

	Carrying	Estimated	Carrying	Estimated
	Value	Fair Value	Value	Fair Value
	December 31, 2008		December 31, 2007
	(in millions)
Financial assets
Cash and cash equivalents	$    23.9	$    23.9	$    14.2	$    14.2
Fair value of derivative contracts- short term	431.3	431.3	78.1	78.1
Fair value of derivative contracts- long term	106.3	106.3	7.8	7.8
Financial liabilities
Short-term debt	231.1	231.1	260.6	260.6
Fair value of derivative contracts- short term	0.5	0.5	9.3	9.3
Long-term debt	2,122.2	1,994.8	1,123.5	1,139.1
Fair value of derivative contracts – long-term	69.0	69.0	22.1	22.1

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

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

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

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

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Note 8 – Rate Regulation and Other Regulatory Assets and Liabilities

Rate Regulation

Questar Gas Rate Changes

Questar Gas filed a general rate case in Utah in December 2007. The PSCU allowed Questar Gas to increase its non-gas distribution revenues by an annualized $12.0 million beginning August 15, 2008. The PSCU authorized a 10.0% return on equity. Questar Gas filed a general rate case in Wyoming in August 2008.  Hearings are scheduled for the second quarter of 2009.

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 beginning in November. Questar Gas rec orded a $1.0 million revenue increase in 2008, a $2.5 million revenue increase in 2007 and a $1.7 million revenue reduction in 2006 in accordance with the CET.

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 $18.9 million were incurred in 2008 and $6.2 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 6.1 years as of December 31, 2008.

·

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. Questar Gas is allowed to recover $5.1 million per year. Costs incurred in excess of this amount will be recovered in future rate changes.

·

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.

A list of regulatory assets follows:

	December 31,
Current regulatory assets	2008	2007
	(in millions)
Demand side management	$17.8	$5.6
Conservation enabling tariff		1.3
Deferred production taxes	2.8	2.5
	$20.6	$9.4

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	December 31,
Long-term regulatory assets	2008	2007
	(in millions)
Cost of reacquired debt	$12.2	$13.3
Questar Gas pipeline integrity costs	7.0	7.3
Asset retirement obligations – cost-of-service gas wells	3.6	3.9
Income taxes recoverable from customers	2.2	2.5
Other	1.3	1.4
	$26.3	$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.

Long-term regulatory liabilities are included with other long-term liabilities in the Consolidated Balance Sheets. A list of regulatory liabilities follows:

	December 31,
	2008	2007
	(in millions)
Long-term regulatory liabilities
Postretirement medical	$5.8	$4.9
Income taxes refundable to customers	1.3	1.7
	$7.1	$6.6

Note 9 – Debt

The Company has short-term line-of-credit commitments from several banks under which it may borrow up to $365 million at December 31, 2008. These credit lines have interest-rate options 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,
	2008	2007
	(in millions)
Commercial paper with variable-interest rates	$151.1	$260.6
Weighted-average interest rate	4.59%	5.70%
Short-term bank debt with variable-interest rates	$  80.0
Weighted-average interest rate	2.34%

All long-term notes and the term-bank loan are unsecured obligations and rank equally with all other unsecured liabilities. Market Resources’ revolving-credit facility had $450.0 million outstanding and a weighted-average interest rate of 1.60% at December 31, 2008. This credit agreement carries an annual commitment fee of 0.115% of the unused balance. At December 31, 2008, Market Resources could pay dividends of $891.0 million without violating the terms of its debt covenants. The terms of the Questar Pipeline and Questar Gas debt obligations do not have dividend-payment restrictions.

In January 2008, Questar Pipeline sold $200.0 million of 10-year notes with a 5.83% interest rate and used the proceeds to repay maturing long-term debt and short-term intercompany debt.

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In March 2008, Questar Gas sold $50.0 million of 10-year notes with a 6.3% interest rate and $100.0 million of 30-year notes with a 7.2% interest rate. Proceeds from the Questar Gas borrowings were used to repay maturing long-term debt and short-term intercompany debt.

In March 2008, Market Resources filed a shelf registration with the SEC to sell up to $700.0 million of debt securities and to use the net proceeds to repay bank borrowings and to finance certain capital expenditures as well as for general corporate purposes, including working capital. In April 2008, Market Resources sold $450.0 million of 10-year notes with a 6.8% interest rate. In March 2008, Market Resources also entered into a new $800.0 million five-year revolving-credit facility. The net proceeds from the sale of the notes and funds borrowed under the revolving-credit facility were used to reduce short-term bank debt described in Note 4. In an October 2008 filing with the SEC, Market Resources increased the unused portion of its March 2008 shelf registration from $250.0 million to $300.0 million.

The details of long-term debt are as follows:

	December 31,
	2008	2007
	(in millions)
Market Resources
Revolving-credit facility, 1.60% at December 31, 2008, due 2013	$   450.0
Revolving term loan, 5.55% at December 31, 2007, due 2012		$   100.0
7.50% notes due 2011	150.0	150.0
6.05% notes due 2016	250.0	250.0
6.80% notes due 2018	450.0
Questar Pipeline
Medium-term notes 6.45% to 7.55%, due 2009 to 2018	252.2	310.5
5.83% notes due 2018	200.0
Questar Gas
Medium-term notes 5.02% to 6.91%, due 2011 to 2018	220.0	263.0
6.30% notes due 2018	50.0
7.20% notes due 2038	100.0
Five-year term loan, 5.19% at December 31, 2007, due 2010		50.0
Total Long-Term Debt Outstanding	2,122.2	1,123.5
Less current portion	(42.0)	(101.3)
Less unamortized-debt discount	(1.3)	(1.0)
Total Long-Term Debt	$2,078.9	$1,021.2

Maturities of long-term debt for the five years following December 31, 2008, are as follows:

	(in millions)
2009	$42.0
2010
2011	332.0
2012	91.5
2013	492.0

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:

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	Year Ended December 31,
	2008	2007	2006
	(in millions)
Federal
Current	$  4.5	$  93.7	$141.6
Deferred	362.3	173.8	90.5
State
Current	(3.6)	5.9	12.5
Deferred	15.2	17.6	11.3
Deferred investment tax credits recognized	(0.4)	(0.4)	(0.4)
	$378.0	$290.6	$255.5

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

	Year Ended December 31,
	2008	2007	2006
Federal income 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	0.7	1.9	2.2
Domestic production benefit		(0.2)	(0.3)
Percentage depletion			(0.1)
Amortize investment-tax credits related to
rate-regulated assets		(0.1)	(0.1)
Tax benefits from dividends paid to ESOP	(0.1)	(0.1)	(0.2)
Other		(0.1)
Effective income tax rate	35.6%	36.4%	36.5%

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

	December 31,
	2008	2007
	(in millions)
Deferred tax liabilities
Property, plant and equipment	$1,422.8	$992.3
Energy-price derivatives	13.6
Total deferred tax liabilities	1,436.4	992.3
Deferred tax assets
Energy-price derivatives		6.0
Employee benefits and compensation costs	102.3	43.9
Total deferred tax assets	102.3	49.9
Deferred income taxes – noncurrent	$1,334.1	$942.4
Deferred income taxes – current
Energy-price derivatives	$160.4	$ 26.2
Other	(29.8)	(21.3)
Deferred income taxes – current liability	$130.6	$   4.9

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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. A liability is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. Disclosures are provided for contingencies reasonably likely to occur which would have a material adverse effect on the Company’s financial position, results of operations or cash flows. Some of the claims involve highly complex issues relating to liability, damages and other matters subject to substantial uncertainties and, therefore, the probability of liability or an estimate of loss cannot be reasonably determined.

Environmental Claims

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

Commitments

Historically, 40 to 50% of Questar Gas gas-supply portfolio has been provided from cost-of-service reserves.  In 2008, the remainder of the gas supply was purchased using index-based or fixed-price contracts. Questar Gas has commitments to purchase gas for $88.6 million in 2009, $44.2 million in 2010, $31.1 million in 2011, $27.8 million in 2012 and $27.8 in 2013. 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 $395.5 million in 2008, $374.8 million in 2007 and $429.5 million in 2006. 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 the winter).

Questar Gas has third-party transportation commitments requiring yearly payments of $4.9 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:

	(in millions)
2009	$   8.0
2010	8.0
2011	7.7
2012	5.8
2013	3.8
2014 through 2028	24.4

Questar sold its headquarters building under a sale-and-leaseback arrangement committing the Company to occupy the building through January 12, 2012. Rental expense amounted to $6.8 million in 2008, $5.8 million in 2007 and $5.3 million in 2006.

Minimum future payments under the terms of long-term operating leases for the Company’s primary office locations are as follows:

	(in millions)
2009	$   7.2
2010	7.5
2011	7.6
2012	5.7
2013	3.0

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Note 12 – Employee Benefits

Pension and Postretirement Benefits  

The Company has defined-benefit pension and life insurance plans covering a majority of its employees and a postretirement medical plan providing coverage to less than half 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 Range
	2008	2007	2008	2007
Domestic equity securities	37%	43%	35-45%	40-50%
Foreign equity securities	20	24	20-30	15-25
Debt securities	38	28	26-34	26-34
Real estate securities	4	5	3-7	3-7
Other	1		0-3	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.

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The pension projected-benefit obligation and postretirement benefit accumulated benefit obligation were measured using a 6.5% discount rate at December 31, 2008 and 2007. 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 2009. The pension plan accumulated benefit obligation was $375.6 million at December 31, 2008. Plan obligations and fair value of plan assets are shown in the following table:

	Pension			Postretirement Benefits
	2008		2007	2008	2007
	(in millions)
Change in benefit obligation
Benefit obligation at January 1,	$418.4	$421.5		$76.3	$83.0
Service cost	9.6	10.4		0.7	0.9
Interest cost	27.7	24.7		4.6	4.4
Change in plan assumptions	0.8	(38.3)			(6.0)
Actuarial loss	14.7	14.3		0.1	0.4
Benefits paid	(15.0)	(14.2)		(5.6)	(6.4)
Benefit obligation at December 31,	456.2	418.4		76.1	76.3
Change in plan assets
Fair value of plan assets at January 1,	344.6	314.4		46.1	45.2
Actual gain (loss) on plan assets	(96.6)	25.7		(12.1)	3.4
Company contributions to the plan	15.2	18.7		2.9	3.9
Benefits paid	(15.0)	(14.2)		(5.6)	(6.4)
Fair value of plan assets at December 31,	248.2	344.6		31.3	46.1
Underfunded status (current and long-term)	($208.0)	($73.8)		($44.8)	($30.2)

The projected 2009 pension funding is expected to be $18.4 million. Estimated benefit-plan payments for the five years following 2008 and the subsequent five years aggregated are as follows:

	Pension	Postretirement Benefits
	(in millions)
2009	$  17.0	$  4.8
2010	15.3	4.9
2011	16.4	5.0
2012	17.6	5.1
2013	19.3	5.1
2014 through 2018	130.0	27.8

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,
	2008	2007	2006	2008	2007	2006
	(in millions)			(in millions)
Service cost	$   9.6	$10.4	$   9.8	$0.7	$0.9	$ 0.9
Interest cost	27.7	24.7	22.8	4.6	4.4	4.5
Expected return on plan assets	(26.7)	(24.1)	(21.0)	(3.5)	(3.4)	(3.0)

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Prior service and other costs	1.2	1.2	1.5	1.9	1.9	1.9
Recognized net actuarial loss	4.4	7.2	6.2		0.2	0.2
Special-termination benefits	0.6	0.6	1.4
Accretion of regulatory liability				0.8	0.8	0.8
Periodic expense	$   16.8	$20.0	$20.7	$4.5	$4.8	$5.3

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

	2008	2007	2006
Discount rate	6.5%	5.75%	6.0%
Rate of increase in compensation	4.0	4.0	4.0
Long-term return on assets	8.0	8.0	8.0
Health-care inflation rate	7.0 decreasing to 5.0% by 2011	8.0 decreasing to 5.0% by 2011	9.0 decreasing to 5.0% in 2011

The 2009 estimated pension expense is $21.6 million. In 2009, $5.9 million of estimated actuarial loss and $1.2 million of prior service cost for the pension plan will be amortized from accumulated other comprehensive income. The 2009 estimated post-retirement expense is $4.1 million excluding amortization of a regulatory liability. In 2009, $1.9 million of net transition obligation and $1.0 million of estimated actuarial loss 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 $1.1 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 $1.0 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 $ 9.1 million in 2008, $8.1 million in 2007 and $6.7 million in 2006.

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 20.6%.

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

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

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d. Wexpro conducts developmental-oil drilling on productive oil properties and bears any costs of dry holes. Oil discovered from these properties is sold at market prices with the revenues used to recover operating expenses and to give Wexpro a return on its investment in successful wells. The after-tax rate of return is adjusted annually and is approximately 17.6%. Any operating income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas with Wexpro retaining 46%. Questar Gas received oil-income sharing of $6.1 million in 2008, $4.9 million in 2007 and $5.5 million in 2006.

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 and the yearly average rate of return for 2008 and the previous two years are shown in the table below:

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

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. Following is a summary of operations by line of business for the three years ended December 31, 2008:

		Questar	Interco.				Questar		Gas	Energy		Questar		Questar
		Consol.	Trans.				E&P	Wexpro	Managmt.	Trading		Pipeline		Gas		Corp.
		(in millions)
2008
Revenues
From unaffiliated customers		$3,465.1					$1,392.1	$31.1	$265.9	$608.1		$173.7		$  994.2
From affiliated companies					($1,149.7)			209.9	24.3	834.5		74.9		6.1
Total revenues		3,465.1			(1,149.7)		1,392.1	241.0	290.2	1,442.6		248.6		1,000.3
Operating expenses
Cost of natural gas and other   products sold		1,007.6			(1,136.0)		0.5			1,404.4		1.8		736.9
Operating and maintenance		374.0			(1.7)		125.4	23.5	95.0	1.2		43.5		87.1
General and administrative		159.7			(5.9)		55.8	13.7	23.7	3.0		30.4		38.7		$0.3
Production and other taxes		164.9					104.0	37.7	2.6	0.3		7.8		11.9		0.6
Depreciation, depletion and
amortization		494.4					330.9	48.5	28.7	1.9		42.7		41.5		0.2
Other operating expenses	88.7			(6.1)		73.9		6.1	0.8				14.0
Total operating expenses	2,289.3			(1,149.7)		690.5		129.5	150.8		1,410.8		140.2		916.1		1.1
Net gain (loss) from asset sales	64.7					60.4		(0.2)					4.5
Operating income (loss)	1,240.5					762.0		111.3	139.4		31.8		112.9		84.2		(1.1)
Interest and other income (expense)	(61.5)			(78.4)		(71.7)		6.6	(9.0)		69.1		10.6		5.2		6.1
Income from unconsol. affiliates	2.3					0.5			1.2				0.6
Interest expense	(119.5)			78.4		(58.3)		(2.7)	(3.6)		(66.2)		(32.7)		(25.2)		(9.2)
Income tax expense	(378.0)					(224.5)		(41.3)	(46.5)		(12.6)		(33.4)		(24.0)		4.3
Net income	$683.8					$408.0		$73.9	$81.5		$22.1		$58.0		$40.2		$0.1
Identifiable assets	$8,630.7					$4,507.8		$567.2	$914.2		$213.5		$1,114.9		$1,300.1		$13.0

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Goodwill	70.0				60.2								4.2					5.6
Investment in unconsol. affiliates	68.4							40.8					27.6
Capital expenditures	2,485.7				1,777.3		143.8	357.9		1.5			78.3					126.3				0.6
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
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)

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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

Note 15 – Unaudited Quarterly Financial Information

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

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 unaudited quarterly financial information:

	First	Second	Third	Fourth
	Quarter	Quarter	Quarter	Quarter	Year
	(in millions, except per-share amounts)
2008
Revenues	$1,000.5	$825.8	$760.0	$878.8	$3,465.1
Operating income	308.6	284.6	375.5	271.8	1,240.5
Net income	185.8	172.6	204.2	121.2	683.8
Basic earnings per common share	1.08	1.00	1.18	0.70	3.96
Diluted earnings per common share	1.05	0.98	1.16	0.69	3.88
2007
Revenues as reported	$872.1	$556.7	$497.4	$800.4	$2,726.6
Revenues as restated	896.2	577.7	509.2	743.5	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

Note 16 – Supplemental Gas and Oil Information (Unaudited)

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

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

Questar E&P Activities

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

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Capitalized Costs

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

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

Costs Incurred

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

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

Results of Operation

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

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

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Estimated Quantities of Proved Gas and Oil Reserves

Estimates of the Company’s proved gas and oil reserves have been prepared by Ryder Scott Company and Netherland, Sewell & Associates, Inc., independent reservoir engineers, in accordance with the SEC’s Regulation S-X and SFAS 69 “Disclosures about Oil and Gas Producing Activities.” The table below summarizes the changes in the estimated net quantities of proved natural gas, oil and NGL reserves for each of the three years in the period ended December 31, 2008. The quantities reported are based on existing economic and operating conditions at the time the estimates were made. All gas and oil reserves reported are located in the United States. The Company does not have any long-term supply contracts with foreign governments or reserves of equity investees.

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

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

^(b)Estimates of the quantity of proved reserves from the Company’s Pinedale Anticline leasehold in western Wyoming have changed substantially over time as a result of numerous factors including, but not limited to, additional development drilling activity, producing well performance and an improved understanding of Lance Pool reservoir characteristics. The continued analysis of new data has led to progressive increases in estimates of original gas-in-place in the Lance Pool reservoirs at Pinedale

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and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. The Wyoming Oil and Gas Conservation Commission (WOGCC) has approved 10-acre-density drilling for Lance Pool wells on about 12,700 (gross) of the Company’s 17,872 acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the estimated productive limits of the Company’s core acreage in the field. In January 2008, the WOGCC approved five-acre-density drilling for Lance Pool wells on about 4,200 gross acres of Market Resources Pinedale leasehold. If five-acre-density development is appropriate for a majority of its leasehold, the Company currently estimates up to an additional 1,500 wells will be required to fully develop the Lance Pool on its acreage. The Company will continue to disclose future revisions to proved reserves associated with Pinedale increased density drilling separately.

Standardized Measure of Future Net Cash Flows Relating to Proved Reserves

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

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

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

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

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

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

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Net change in income taxes	711.2	(635.0)	760.8
Other	(122.5)	(13.1)	21.9
Net change	(832.1)	1,266.2	(1,139.3)
Balance at December 31,	$2,001.9	$2,834.0	$1,567.8

Cost-of-Service Activities

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

Capitalized Costs

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

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

Costs Incurred

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

Results of Operation

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

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

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

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

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

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

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

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

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, 2008
Allowance for bad debts	$6.0	$7.0		($4.5)	$8.5
Allowance for notes receivable	2.8		(2.8)

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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

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

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

ITEM 9A.  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, 2008. Based on such evaluation, such officers have concluded that, as of December 31, 2008, 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, 2008, 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, 2008. 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, 2008, is effective based on those criteria.

The effectiveness of Questar’s internal control over financial reporting as of December 31, 2008, 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, 2008, 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 included in the accompanying Management’s Assessment 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 unauthoriz ed acquisition, use or 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, 2008, 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, 2008 and 2007, 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, 2008 of Questar Corporation and our report dated February 24, 2009 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Salt Lake City, Utah

February 24, 2009  

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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 2009 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 2009 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 2009 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 2009 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, 2008, is presented in the definitive Proxy Statement for the Company’s 2009 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 2009 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 2009 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).

Exhibit No.

Description

  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 October 28, 2008.

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. (Exhibit 10.4 to the Annual Report on Form 10-K for 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. (Exhibit 10.7 to the Annual Report on Form 10-K for 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.)

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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 as amended and restated effective October 28, 2008.

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 as amended and restated on October 28, 2008.

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

First 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

First 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 as amended and restated October 28, 2008.

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.)

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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.)

10.34*¹

Second Amendment to Employment Agreement of Keith O. Rattie dated February 28, 2007 (Exhibit 99.1 to current report on Form 8-K dated February 28, 2007.)

10.35*¹

Form of Restricted Stock Agreement dated February 12, 2008 for shares granted to certain key executives. (Exhibit 10.1 to Current Report on Form 8-K dated February 13, 2008.)

10.36*¹

Form of Restricted Stock Agreement dated February 12, 2008 for shares granted to other officers and key employees. (Exhibit 10.2 to Current Report on Form 8-K dated February 13, 2008.)

10.37*¹

Form of Restricted Stock Agreement dated February 12, 2008 for shares granted to non-employee directors. (Exhibit 10.3 to Current Report on Form 8-K dated February 13, 2008.)

10.38*¹

Form of Phantom Stock Agreement dated February 12, 2008 for shares granted to non-employee directors. (Exhibit 10.4 to Current Report on Form 8-K dated February 13, 2008.)

10.39*¹

Form of Option Agreement dated February 12, 2008, for options granted to a key executives. (Exhibit 10.5 to Current Report on Form 8-K dated February 13, 2008.)

10.40*¹

Second Amendment to Employment Agreement of Charles B. Stanley dated December 31, 2008 (Exhibit 99.2 to current report on Form 8-K dated December 31, 2008.)

10.41*¹

Third Amendment to Employment Agreement of Keith O. Rattie dated December 31, 2008 (Exhibit 99.1 to Current Report on Form 8-K dated December 31, 2008.

10.42*¹

Form of Restricted Stock Agreement dated February 10, 2009, for shares granted to other officers. (Exhibit No. 99.2 to Current Report on Form 8-K dated February 10, 2009.)

10.43*¹

Form of Restricted Stock Agreement dated February 10, 2009, for shares granted to non-employee directors. (Exhibit No. 99.3 to Current Report on Form 8-K dated February 10, 2009.)

10.44*¹

Form of Phantom Stock Agreement dated February 10, 2009, for shares granted to non-employee directors. (Exhibit No. 99.4 to Current Report on Form 8-K dated February 10, 2009.)

10.45*¹

Form of Option Agreement dated February 10, 2009, for options granted to certain key executives. (Exhibit No. 99.5 to Current Report on Form 8-K dated February 10, 2009.)

10.46*¹

Form of Option Agreement dated February 10, 2009, for options granted to other officers. (Exhibit No. 99.6 to Current Report on Form 8-K dated February 10, 2009.)

12.

Ratio of earnings to fixed charges.

14.

Business Ethics and Compliance Policy.

21.

Subsidiary Information.

23.1.

Consent of Independent Registered Public Accounting Firm.

23.2.

Consent of Independent Petroleum Engineers and Geologists.

23.3.

Consent of Independent Petroleum Engineers and Geologists.

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 2008 FORM 10-K

81

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.

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 2009.

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, 2009

*/s/ Keith O. Rattie

  Keith O. Rattie, Attorney in Fact

QUESTAR 2008 FORM 10-K

82

EXHIBIT INDEX

Exhibit No.

Description

  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 October 28, 2008.

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. (Exhibit 10.4 to the Annual Report on Form 10-K for 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. (Exhibit 10.7 to the Annual Report on Form 10-K for 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 as amended and restated effective October 28, 2008.

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.)

QUESTAR 2008 FORM 10-K

83

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 as amended and restated on October 28, 2008.

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

First 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

First 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 as amended and restated October 28, 2008.

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.)

10.34*¹

Second Amendment to Employment Agreement of Keith O. Rattie dated February 28, 2007 (Exhibit 99.1 to Current Report on Form 8-K dated February 28, 2007.)

10.35*¹

Form of Restricted Stock Agreement dated February 12, 2008 for shares granted to certain key executives. (Exhibit 10.1 to Current Report on Form 8-K dated February 13, 2008.)

10.36*¹

Form of Restricted Stock Agreement dated February 12, 2008 for shares granted to other officers and key employees. (Exhibit 10.2 to Current Report on Form 8-K dated February 13, 2008.)

10.37*¹

Form of Restricted Stock Agreement dated February 12, 2008 for shares granted to non-employee directors. (Exhibit 10.3 to Current Report on Form 8-K dated February 13, 2008.)

10.38*¹

Form of Phantom Stock Agreement dated February 12, 2008 for shares granted to non-employee directors.

QUESTAR 2008 FORM 10-K

84

(Exhibit 10.4 to Current Report on Form 8-K dated February 13, 2008.)

10.39*¹

Form of Option Agreement dated February 12, 2008, for options granted to a key executives. (Exhibit 10.5 to Current Report on Form 8-K dated February 13, 2008.)

10.40*¹

Second Amendment to Employment Agreement of Charles B. Stanley dated December 31, 2008 (Exhibit 99.2 to Current Report on Form 8-K dated December 31, 2008.)

10.41*¹

Third Amendment to Employment Agreement of Keith O. Rattie dated December 31, 2008 (Exhibit 99.1 to current report on Form 8-K dated December 31, 2008.

10.42*¹

Form of Restricted Stock Agreement dated February 10, 2009, for shares granted to other officers. (Exhibit No. 99.2 to Current Report on Form 8-K dated February 10, 2009.)

10.43*¹

Form of Restricted Stock Agreement dated February 10, 2009, for shares granted to non-employee directors. (Exhibit No. 99.3 to Current Report on Form 8-K dated February 10, 2009.)

10.44*¹

Form of Phantom Stock Agreement dated February 10, 2009, for shares granted to non-employee directors. (Exhibit No. 99.4 to Current Report on Form 8-K dated February 10, 2009.)

10.45*¹

Form of Option Agreement dated February 10, 2009, for options granted to certain key executives. (Exhibit No. 99.5 to Current Report on Form 8-K dated February 10, 2009.)

10.46*¹

Form of Option Agreement dated February 10, 2009, for options granted to other officers. (Exhibit No. 99.6 to Current Report on Form 8-K dated February 10, 2009.)

12.

Ratio of earnings to fixed charges.

14.

Business Ethics and Compliance Policy.

21.

Subsidiary Information.

23.1.

Consent of Independent Registered Public Accounting Firm.

23.2.

Consent of Independent Petroleum Engineers and Geologists.

23.3.

Consent of Independent Petroleum Engineers and Geologists.

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.

QUESTAR 2008 FORM 10-K

85

EX-10

Exhibit 10.2.

QUESTAR CORPORATION
ANNUAL MANAGEMENT INCENTIVE PLAN

(As amended and restated on October 28, 2008)

Paragraph 1.  Name.  The name of this Plan is the Questar Corporation Annual Management Incentive Plan (the “Plan”).

Paragraph 2.  Purpose.  The purpose of the Plan is to provide an incentive to officers and key employees of Questar Corporation (the “Company”) for the accomplishment of major organizational and individual objectives designed to further the Company’s efficiency, profitability, and growth.

Paragraph 3.  Administration.  The Management Performance Committee (“Committee”) of the Company’s Board of Directors (“Board”) shall have full power and authority to interpret and administer the Plan.  Such Committee shall consist of no less than three disinterested members of the Company’s Board.  

Paragraph 4.  Participation.  Within 60 days after the beginning of each year, the Committee shall nominate Participants from the officers and key employees for such year.  The Committee shall also establish a target bonus for the year for each Participant expressed as a percentage of base salary or specified portion of base salary.  Participants shall be notified of their selection and their target bonus as soon as practicable.

Paragraph 5.  Determination of Performance Objectives.  Within 60 days after the beginning of each year, the Committee shall establish target, minimum and maximum performance objectives for the Company and/or for its major operating subsidiaries and shall determine the manner in which the target bonus is allocated among the performance objectives.  The Committee shall also recommend a dollar maximum for payments to Participants for any Plan year.  The Board shall take action concerning the recommended dollar maximum within 60 days after the beginning of the Plan year.  Participants shall be notified of the performance objectives as soon as practicable once such objectives have been established.

Paragraph 6.  Determination and Payment of Awards.  As soon as practicable, but in no event more than 60 days after the close of each year during which the Plan is in effect, the Committee shall compute incentive awards for eligible Participants in such amounts as the members deem fair and equitable, giving consideration to the degree to which the Participant’s performance has contributed to the performance of the Company and its affiliated companies and using the target bonuses and performance objectives previously specified.  Aggregate awards calculated under the Plan shall not exceed the maximum limits approved by the Board for the year involved.  To be eligible to receive a payment, the Participant must be actively employed by the Company or an affiliate as of the date of distribution except as provided in Paragraph 7 and must not have been placed on probatio n during such year.

The Committee has the discretion to determine that any given non-officer Participant has earned up to the full amount of his target bonus for any year in which he has performed on a superior

level, despite the failure of the Company and its affiliated companies to achieve performance objectives that would otherwise result in a payment of such target bonus.  The Committee shall exercise this discretion only if it receives a joint recommendation by the Company’s senior officer of the group in which the Participant works and the Company’s Chief Executive Officer.

All awards shall be made in cash no later than the 15^th day of the 3^rd month following the end of the year for which performance is measured.

Paragraph 7.  Termination of Employment.

(a)

In the event a Participant ceases to be an employee during a year by reason of death, disability, approved retirement, or a reduction in force, the Participant's award if any, determined in accordance with Paragraph 6 for the year of such event, shall be reduced to reflect partial participation by multiplying the award by a fraction equal to the months of participation during the applicable year through the date of termination rounded up to whole months divided by 12.

For the purpose of this Plan, approved retirement shall mean any termination of service on or after age 55 with 10 years of service.  For the purpose of this Plan, disability shall mean any termination of service that results in payments under the Company's Long-term Disability Plan.  A reduction in force, for the purpose of this Plan, shall mean any involuntary termination of employment due to the Company’s economic condition, sale of assets, shift in focus, or other reasons independent of the Participant’s performance.

The entire amount of any award that is determined after the death of a Participant shall be paid to the Participant's beneficiary determined in accordance with the terms of Paragraph 10.

All payments under this Section 7a shall be made at the time specified in Section 6.

(b)

In the event a Participant ceases to be an employee during a year by reason of a Change in Control, he shall be entitled to receive all amounts deferred by him prior to February 12, 1991.  He shall also be entitled to an award for the year of such event as if he had been an employee throughout such year ("Post-CIC Bonus").  The entire amount of any award for such year shall be paid in a lump sum at the time specified in Section 6.  Such amounts shall be paid in cash.  Notwithstanding the foregoing, in no event shall a Participant who is a participant in the Company’s Executive Severance Compensation Plan as of the Change in Control be entitled to any Post-CIC Bonus.

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 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 conse nt solicitation, relating to the election of directors of the

2

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 other 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 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 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.

Paragraph 8.  Interest on Previously Deferred Amounts.  Amounts voluntarily deferred prior to February 12, 1991, shall be credited with interest from the date the payment was first available in cash to the date of actual payment.  Such interest shall be calculated at a monthly rate using the typical rates paid by major banks on new issues of negotiable Certificates of Deposit in the amounts of $1,000,000 or more for one year as quoted in The Wall Street Journal on the Thursday closest to the end of the month or other published source of rates as identified by the Company’s Treasury department.

Paragraph 9.  Coordination with Deferred Compensation Plan.  Some Participants are entitled to defer the receipt of all or a portion of their bonuses under the terms of the Company’s Deferred Compensation Plan, which became effective November 1, 1993.  Any bonuses deferred pursuant to the Deferred Compensation Plan shall be accounted for and distributed according to the terms of such plan and the elections made by the Participant.

Paragraph 10.  Death and Beneficiary Designation.  In the event of the death of a Participant, amounts previously deferred by the Participant, together with credited interest to the date of death, shall become payable.  Each Participant shall designate a beneficiary to receive any amounts that become payable after death under this Paragraph or Paragraph 7.  In the event that no valid beneficiary designation exists at death, all amounts due shall be paid as a lump sum to the Participant's beneficiary(ies) designated by the Participant (or deemed by law to be designated) under the Company's Employee Investment Plan, or if none, to the estate of the Participant.

3

Paragraph 11.  Amendment of Plan.  The Company’s Board, at any time, may amend, modify, suspend, or terminate the Plan, but such action shall not affect the awards and the payment of such awards for any prior years.  The Company’s Board cannot amend, modify, suspend, or terminate the Plan in any year in which a Change of Control has occurred without the written consent of the Participants.  The Plan shall be deemed suspended for any year for which the Board has not fixed a maximum dollar amount available for awards.

Paragraph 12.  Nonassignability..  No right or interest of any Participant under this Plan shall be assignable or transferable in whole or in part, either directly or by operation of law or otherwise, including, but not by way of limitation, execution, levy, garnishment, attachment, pledge, bankruptcy, or in any other manner, and no right or interest of any Participant under the Plan shall be liable for, or subject to, any obligation or liability of such Participant.  Any assignment, transfer, or other act in violation of this provision shall be void.

Paragraph 13.  Effective Date of the Plan.  The Plan was originally effective with respect to the fiscal year beginning January 1, 1984, and shall remain in effect until it is suspended or terminated as provided by Paragraph 11.  This amendment and restatement of the Plan is effective October 28, 2008.

Paragraph 14.  409A Compliance.  All bonuses payable hereunder are intended to be "short-term deferrals" exempt from the requirements imposed by Section 409A of the Code, and this Plan shall be interpreted accordingly.

Dated this ______ day of ______________, 2008.

QUESTAR CORPORATION

By:_______________________________________

Keith O. Rattie

Chairman, President & CEO

4

EX-10

Exhibit 10.14.

QUESTAR CORPORATION

LONG-TERM CASH INCENTIVE PLAN

(as amended and restated on October 28, 2008)

Section 1.

Purpose.

The Questar Corporation Long-term Cash Incentive Plan (the "Plan") is designed to encourage key employees of Questar Corporation and its affiliated companies (the "Company") to focus attention on the long-term profitability and growth of the Company, thereby serving the interests of the Company's shareholders and to align employee incentives with shareholder value creation.

Section 2.

Definitions.

"Board" means the Board of Directors of the Company or a successor to the Company.

"Code" means the Internal Revenue Code of 1986, as amended from time to time.

"Committee" means the Management Performance Committee of the Board of Directors, which is comprised wholly of independent, outside directors.

"Covered Employee" means a Key Employee 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 $1,000,000 for the Performance Period, as provided in Section 162(m) of the Code.

"Designated Beneficiary" means the beneficiary designated by the Key Employee, in a manner determined by the Committee, to receive amounts due the Key Employee in the event of the Key Employee's death.  In the absence of an effective designation by the Key Employee, Designated Beneficiary shall mean the Key Employee's beneficiary(ies) designated by the Key Employee (or deemed by law to be designated) under Questar Corporation’s Employee Investment Plan, or if no such designation, to the Key Employee’s estate.

"Disability" means a condition that renders a Key Employee 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 twelve months.  The foregoing definition of Disability shall be interpreted in a manner consistent with Section 409A of the Code and relevant guidance issued thereunder.

"Employer" means the Company and any affiliate that agrees to bear the costs of having its Key Employees participate in the Plan.  The term shall also mean any successor to the Company.

"Fiscal Year" means the fiscal year of the Company.

"Key Employee" means an officer, manager or senior professional within the Company who plays a key role in achieving the Company's strategic plans and total return goals.  To participate in the Plan, an employee must be nominated by the Company's President and Chief Executive Officer and confirmed by the Committee.  An employee's status as an officer, manager, or senior professional does not make him automatically eligible to participate in the Plan.

"Performance Goals" means the objective(s) established by the Committee for a Performance Period.  As a general rule, the Performance Goal shall be Total Shareholder Return or other performance measure deemed by the Committee to be closely linked to long-term shareholder value.

"Performance Period" or "Period" means the period of years selected by the Committee during which Total Return or other Performance Goals is measured for purposes of determining the extent to which a Key Employee has earned his Target Bonus or any portion or multiple of it.  A Performance Period must be at least two years in length.

"Target Bonus" means the dollar amount specified for each Key Employee within the 60 days after the beginning of a Performance Period.

"Termination of Employment" means the date on which a Key Employee shall cease to serve as an employee for any reason.

"Total Shareholder Return" means the change in stock price for the relevant period plus any dividends the Company pays its shareholders during the year, expressed as a percentage.  

Section 3.

Administration.

The Plan shall be administered by the Committee, unless otherwise determined by the Board.  The Committee shall have sole and complete authority to adopt, alter, and repeal such 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 parties, including the Company, stockholders, Key Employees, and Designated Beneficiaries.

Section 4.

Eligibility.

When reviewing an employee's nomination for Plan participation, the Committee may consider such factors as the employee's functions and responsibilities and the employee's past, present, and future contributions to the Company's growth and profitability.

Nothing contained in the Plan shall confer upon any Key Employee 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.

2

Section 5.

Determination of Key Employees, Target Bonuses, and Performance Goals.

Within 60 days after the beginning of each year, the Committee shall name individuals to participate in the Plan as Key Employees, determine each Key Employee's Target Bonus, and approve the Performance Goal(s) (with minimum payout portions of Target Bonuses and maximum payout multiples of Target Bonuses) for a defined Performance Period.  At such time, the Committee shall also approve the peer companies for the Total Shareholder Return comparison and approve the maximum amount that can be paid pursuant to the terms of the Plan at the end of the Performance Period.

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)  economic value added and economic profit; or  (f)  growth in earnings per share.

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.  Any payment under this Plan to a Covered Employee 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 payment that such applicable Performance Goals relating to the payment are satisfied.  (Approved minutes of the Committee may be used for this purpose.)

The maximum payment that may be paid to any Covered Employee under the Plan for any Performance Period shall be $1,500,000.

Section 6.

Determination of Awards.

Within 60 days after the end of each Performance Period, the Committee shall compute incentive awards for each Key Employee, using the Target Bonus and Performance Goals previously approved.  All awards shall be made in cash and in one installment in the year following the year in which the Performance Period ends, generally within the first 60 days of such following year.  Aggregate awards calculated pursuant to the terms of the Plan shall not exceed the maximum limit approved by the Board of Directors for the Performance Period involved.  To be eligible to receive a payment, the Key Employee must be actively employed by the Company or an affiliate as of the date of distribution except as provided in Section 7 and must not have been placed on probation at any time during such period.

3

Section 7.

Termination of Employment.

In the event a Key Employee ceases to be an employee during a Performance Period for any reason other than death, disability, retirement, or a Change in Control, he shall not be entitled to any payment pursuant to the terms of the Plan.  If a Key Employee terminates employment as a result of death, Disability, or retirement, his award for the Performance Period (if any), as calculated pursuant to Section 6, shall be prorated based on the length of his service during the Performance Period when compared to the entire Period.  For the purpose of this Plan, retirement shall mean any voluntary Termination of Employment on or after age 55 with 10 years of service.  All prorated awards shall be paid to the Key Employee (or his Designated Beneficiary, in the event of his death) at the time specified in Section 6, subject to the requirements of Section 8i, if applicable.

In the event a Key Employee ceases to be an employee during a Performance Period as a result of a Change of Control during a Performance Period, he shall be entitled to receive a payment equal to his Target Bonus for such Performance Period.  Such payment shall be made to him within 30 days after his Termination of Employment, subject to the requirements of Section 8i if applicable.  Notwithstanding the foregoing, in no event shall a Covered Employee who is a participant in the Company’s Executive Severance Compensation Plan as of the Change in Control be entitled to any such payment.

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 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 other 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 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

4

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.

Section 8.

General Provisions.

a.

Other Benefit Plans.  Any cash awards paid under the terms of this Plan do not constitute "compensation" for purposes of the Company's qualified or welfare benefit plans.

b.

Taxes and Withholding.  All cash payments made under the Plan are subject to withholding for federal, state, and other applicable taxes.  The Company shall deduct any taxes required by law to be withheld from all amounts paid to a Key Employee under this Plan.

c.

Source of Funds.  All cash payments made under the Plan will be paid from the Company's general assets and nothing contained in the Plan will require the Company to set aside or hold in trust any funds for the benefit of any Key Employee or his Designated Beneficiary.

d.

No Assignment.  No right or benefit under this Plan will be subject to assignment, pledge, encumbrance, or charge, and any attempt to assign, pledge, encumber, or charge such right or benefit will be void.  No such right or benefit will in any manner be subject to the debts or liabilities of a Key Employee.

e.

Amendment of Plan.  The Company's Board of Directors, at any time, may amend, modify, suspend, or terminate the Plan, but such action shall not affect the cash awards earned during any given Performance Period.  No amendment to change the maximum award payable to a Covered Employee, the definition of Covered Employee, or the enumerated Performance Goals shall be effective without shareholder approval.  The Company's Board of Directors cannot amend, modify, suspend, or terminate the Plan following a Change in Control in any manner that would adversely affect Performance Periods existing as of the date of such Change in Control, without the written consent of the affected Key Employees.

f.

Successor.  The Company shall require any Successor or assignment, whether direct, indirect, by purchase, merger, consolidation or otherwise, to all or substantially all of the business and/or assets of the Company to assume the obligations under this Plan in the same manner and to the same extent that the Company would be required to perform if no such successor assignment had taken place.

g.

Choice of Law.  This Plan will be governed by and construed in accordance with applicable federal law and, to the extent not preempted by federal law, in accordance with the laws of the state of Utah.

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h.

Effective Date of the Plan.  The Plan was originally effective with respect to the fiscal year beginning January 1, 2004.  The amendment and restatement of the Plan is effective as of October 28, 2008. The Plan shall remain in effect until it is suspended or terminated as provided in Section 8e.

i.

409A Compliance.  This Plan and all bonuses payable hereunder are intended to comply with the requirements imposed by Section 409A of the Code, and this Plan shall be interpreted accordingly.  In the event that the Committee determines that all or any portion of any payments provided hereunder are deferred compensation subject to Code Section 409A, then, with respect to any Key Employee who is a “specified employee” (as defined in Section 409A(2)(B)(i)), all of the payments that (i) are deferred compensation subject to Code Section 409A, (ii) are payable on account of the Key Employee's "separation from service" (as determined in accordance with Code Section 409A and relevant guidance thereunder), and (iii) would otherwise be payable prior to the date that is six (6) months after the separation from service (the “Specified Employee Distribution Date”), shall be withheld by the Company and paid on the Specified Employee Distribution Date or as soon thereafter as is administratively feasible.

Dated this ______ day of ______________, 2008.

QUESTAR CORPORATION

By:_______________________________________

Keith O. Rattie

Chairman, President & CEO

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EX-10

Exhibit 10.17.

QUESTAR CORPORATION

ANNUAL MANAGEMENT INCENTIVE PLAN II

(as amended and restated on October 28, 2008)

Section 1.  Purpose.  

The Questar Corporation Annual Management Incentive Plan II (“AMIP II”) is designed  to provide an incentive to the highest paid officers of Questar Corporation (the “Company”) and its subsidiaries to focus their best efforts to pursue and attain major organizational goals.  The intent with AMIP II is to place a significant portion of the eligible officer’s annual compensation at risk by tying it to specific measurable goals that drive long-term shareholder value.

Section 2.  Definitions.

“Board” means the Board of Directors of the Company or a successor to it.

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

“Committee” means the Management Performance Committee, or its successor committee, which is comprised wholly of independent, outside directors and which must include at least two such directors.

“Covered Employee” means an Employee 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 any given year.

“Designated Beneficiary” means the beneficiary designated by the Covered Employee, in a manner determined by the Committee, to receive amounts due the Covered Employee.  In the absence of an effective designation by the Covered Employee, Designated Beneficiary shall mean the Covered Employee’s beneficiary(ies) designated by the Covered Employee (or deemed by law to be designated) under Questar Corporation’s Employee Investment Plan, or if no such designation, the Covered Employee’s estate.

“Disability” means a condition that renders a Key Employee 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 twelve months.

“Employer” means the Company and any affiliate that is the direct employer of a Covered Employee.

“Fiscal Year” means the fiscal year of the Company.

“Performance Goals” means the specific, measurable goals set by the Committee in writing for any given Fiscal Year.  Performance Goals may include multiple goals and may be based on one

or more operational or financial criteria.  Such goals shall be set by the Committee by such date as is required under Section 162(m) of the Code.  In setting the Performance Goals for the Fiscal Year, the Committee may include one or any combination of the following criteria is either absolute or relative terms, for the Company or any business unit within it:  (a) total shareholder return; (b) return on assets, return on equity or return on capital employed; (c) measures of profitability such as earnings per share, corporate or business unit net income, net income before extraordinary or one-time items, earnings before interest and taxes or earnings before interest, taxes, depreciation and amortization; (d) cash flow from operations; (e) gross or net revenues or gross or net margins; (f) levels of operating expense or other expense items reported on the income statement; (g) measures of custome r satisfaction and customer service; (h) safety; (i) annual or multi-year average reserve growth, production growth or production replacement; (j) efficiency or productivity measures such as annual or multi-year average finding costs, absolute or per unit operating and maintenance costs, lease operating expenses, inside-lease operating expenses, operating and maintenance expense per decatherm or customer or fuel gas reimbursement percentage; (k) satisfactory completion of a major project or organizational initiative with specific criteria set in advance by the Committee defining "satisfactory"; (l) debt ratios or other measures of credit quality or liquidity; and (m) strategic asset sales or acquisitions in compliance with specific criteria set in advance by the Committee.  

“Target Bonus” means the dollar amount specified for each Covered Employee within 60 days after the beginning of a Fiscal Year.

“Termination of Employment” means the date on which a Covered Employee shall cease to serve as an employee for any reason.

Section 3.  Administration.  

The Plan shall be administered by the Committee in conjunction with its administration of the Annual Management Incentive Plan.  The Committee shall have sole and complete authority to adopt, alter, and repeal such administrative rules, guidelines and practices for the operation of the Plan and to interpret the terms and provisions of the Plan.  The Committee also shall have sole and complete authority to determine the extent to which Performance Goals have been achieved.  The Committee’s decisions shall be final and binding upon all parties, including the Company, stockholders, Covered Employees and Designated Beneficiaries.

Section 4.  Eligibility.  

Only Covered Employees are eligible to receive payments under this Plan.  Any payment on a Target Bonus for an employee who is determined not to be a Covered Employee at the time the payment is made shall be paid under the terms of the Company’s Annual Management Incentive Plan, not under the terms of this Plan.

Section 5.  Determination of Awards.

Within 60 days after the beginning of a Fiscal Year, the Committee shall establish a Target Bonus for each Covered Employee and a maximum payout for cash awards granted under the terms of this Plan for such Fiscal Year for attainment of specified Performance Goals by Covered

2

Employees.  Performance Goals must be objective and must satisfy the third-party objectivity standards under Section 162(m) of the Code and regulations adopted pursuant to it.  

Within 60 days after the close of such Fiscal Year, the Committee shall determine cash awards to be paid under the terms of this Plan.  Any payments made under this Plan shall be contingent upon achieving the Performance Goals set in advance for the Fiscal Year in question.  The Committee shall certify in writing prior to approval of any awards that such Performance Goals have been satisfied.  (Approved minutes may used for this purpose.)

The maximum cash payment that may be made to any Covered Employee under the terms of this Plan is $1 million for Fiscal Years 2005 through 2008 and $1.5 million for Fiscal Years beginning with 2009.

The cash payments under this Plan, in aggregate, do not have to equal 100 percent of the maximum payout, but cannot exceed such amount.  The Committee, in its sole discretion, may reduce the cash award otherwise payable to any Covered Employee if it believes that such reduction is in the best interest of the Company and its shareholders, but any reduction cannot result in any increase to one or more other Covered Employees.  The Committee has no discretion to increase the cash award otherwise payable to any Covered Employee.

All payments shall be made in cash and in one installment no later than the 15^th day of the 3^rd month following the end of the Fiscal Year in question.  To be eligible to receive an award, the Covered Employee must be actively employed by the Company or an affiliate as of the date of distribution except as provided below in Section 6.

Section 6.  Termination of Employment.

In the event a Covered Employee ceases to be an employee during a Fiscal Year for any reason other than death, Disability, retirement, or a Change in Control, he shall not be entitled to any payment pursuant to the terms of the Plan.  If a Covered Employee terminates employment as a result of death, Disability, or retirement, his award for the year (if any), as calculated pursuant to Section 5,  shall be prorated  based on the length of his service during the Fiscal Year when compared to the entire period.  For the purpose of this Plan, retirement shall mean any voluntary Termination of Employment on or after age 55 with 10 years of service.  All prorated awards shall be paid to the Covered Employee (or his Designated Beneficiary, in the event of his death) at the time specified in Section 5.

In the event a Covered Employee ceases to be an employee during a Fiscal Year as a result of a Change in Control during a Fiscal Year, he shall be entitled to receive a payment equal to his Target Bonus.  Such payment shall be made to him within 30 days after his Termination of Employment.  Notwithstanding the foregoing, in no event shall a Covered Employee who is a participant in the Company’s Executive Severance Compensation Plan as of the Change in Control be entitled to such payment.

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

3

“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 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 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 v ote 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 other 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 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 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.

Section 7.  Other Provisions.

(a)  Taxes and Withholding.  All cash payments made under the Plan are subject to withholding for federal, state, and other applicable taxes.  The Company shall deduct any taxes required by law to be withheld from all amounts paid to a Covered Employee under this Plan.

(b)  Source of Funds.  All cash payments made under the Plan will be paid from the Company’s general assets and nothing contained in the Plan will require the Company to set aside or hold in trust any funds for the benefit of any Covered Employee or his Designated Beneficiary.

(c)  Coordination with Deferred Compensation Plan.  Covered Employees are entitled to defer the receipt of their cash bonuses under the terms of the Company’s Deferred Compensation Plan, which became effective November 1, 1993.  Any cash bonuses payable under this Plan that are deferred pursuant to the Deferred Compensation Plan shall be accounted for and distributed according to the terms of such plan and the elections made by Covered Employees.

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(d)  No Assignment.  No right or benefit under this Plan will be subject to assignment, pledge, encumbrance, or charge, and any attempt to assign, pledge, encumber, or charge such right or benefit will be void.  No such right or benefit will in any manner be subject to the debts or liabilities of a Covered Employee.

(e)  Amendment of Plan.  The Company’s Board, at any time, may amend, modify, suspend, or terminate the Plan, but such action shall not affect the cash awards earned during any given Fiscal Year.  No amendment to change the maximum award payable to a Covered Employee, the definition of Covered Employee, or the definition of Performance Goals shall be effective without shareholder approval.  The Company’s Board cannot amend, modify, suspend, or terminate the Plan in any year in which a Change in Control has occurred without the written consent of the affected Covered Employees.

(f)  Successor.  The Company shall require any successor or assignee, whether direct, indirect, by purchase, merger, consolidation or otherwise, to all or substantially all of the business and/or assets of the Company to assume the obligations under this Plan in the same manner and to the same extent that the Company would be required to perform if no such successor assignment had taken place.

(g)  Choice of Law  This Plan will be governed by and construed in accordance with applicable federal law and, to the extent not preempted by federal law, in accordance with the laws of the state of Utah.

(h)  Effective Date of the Plan.  The Plan shall was originally effective with respect to the Fiscal Year beginning January 1, 2005.  This amendment and restatement of the Plan is effective October 28, 2008.  The Plan shall remain in effect until it is suspended or terminated as provided in Section 7(e).

(i)

409A Compliance.  All bonuses payable hereunder are intended to be "short-term deferrals" exempt from the requirements imposed by Section 409A of the Code, and this Plan shall be interpreted accordingly.

Dated this ______ day of ______________, 2008.

QUESTAR CORPORATION

By:_______________________________________

Keith O. Rattie

Chairman, President & CEO

5

EX-10

Exhibit 10.24.

QUESTAR CORPORATION

DEFERRED COMPENSATION WRAP PLAN

incorporating the:

Deferred Compensation Program

401(k) Supplemental Program

Effective January 1, 2005

(as amended and restated October 28, 2008)

#1175186 v4 den

QUESTAR CORPORATION

DEFERRED COMPENSATION WRAP PLAN

 (Effective January 1, 2005)

ARTICLE 1

INTRODUCTION

1.1

Purpose.  Questar Corporation hereby establishes this DEFERRED COMPENSATION WRAP PLAN (the “Plan” or “Wrap Plan”) effective January 1, 2005, in order to provide specified benefits to a select group of management and highly compensated employees and to allow such employees to defer the receipt of compensation.  The Plan consists of a main Deferred Compensation Wrap Plan and two component Programs – the Deferred Compensation Program and the 401(k) Supplemental Program (each as described below).  The Wrap Plan contains overriding participation, election, and administrative rules; the Programs contain specific rules regarding the benefits available under the Programs.  The Plan and each of the component programs are designed to replace the Company’s prior (and now frozen) deferred compensation plans, namely the Questar Corporation Deferred Compensation Plan (the
47;Deferred Compensation Plan”), the Questar Corporation Deferred Share Plan (the “Deferred Share Plan”), and the Questar Corporation Deferred Share Make-Up Plan (the “Deferred Share Make-Up Plan”), as of January 1, 2005.

1.2

Status of Plan.  This Plan and its component Programs are intended to be an unfunded, nonqualified deferred compensation arrangement for the purpose of providing deferred compensation to “a select group of management or highly-compensated employees” within the meaning of Sections 201(2), 301(a)(3), and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended. The Plan and its component Programs are also intended to comply with Code section 409A and the regulations and guidance promulgated thereunder.  Finally, each of the component Programs is intended to qualify as a separate “plan, program, or arrangement” for purposes of 4 U.S.C. 114, thus making payments under the 401(k) Supplemental Program subject to state income tax solely of the state in which the recipient of the payment resides or is domiciled at the time payment is made.  Notwithstanding any othe r provision herein, this Plan and its component Programs shall be interpreted, operated and administered in a manner consistent with these intentions.

1.3

Effect of Plan.  The terms of this Plan and each of its component Programs shall govern all amounts deferred on or after January 1, 2005, including any amounts previously deferred or credited under the Deferred Compensation Plan, Deferred Share Plan, or Deferred Share Make-Up Plan (the “Predecessor Plans”) that remain unvested after December 31, 2004.

ARTICLE 2

DEFINITIONS

For purposes of the Plan and each Program established under the Plan, the following terms or phrases shall have the following indicated meanings, unless the context clearly requires otherwise:

2.1

“401(k) Supplemental Program” means the component benefit program of this Plan attached hereto as Appendix B.

2

2.2

“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.  

2.3

“Account” or “Account Balance” means, for each Participant, the account established for his or her benefit under each Program, which records the credit on the records of the Employer equal to the amounts set aside under the Program and the actual or deemed earnings, if any, credited to such account. The Account Balance, and each other specified account or sub-account, shall be a bookkeeping entry only and shall be used solely as a device for the measurement and determination of the amounts to be paid to a Participant, or his or her designated Beneficiary, pursuant to this Plan and its component Programs.

2.4

"Affiliated Company" means the Company and any entity that is treated as the same employer as the Company under Sections 414(b), (c), (m), or (o) of the Code, any entity required to be aggregated with the Company pursuant to regulations adopted under Code section 409A, or any entity otherwise designated as an Affiliated Company by the Employer.

2.5

"Beneficiary" means that person or persons who become entitled to receive a distribution of benefits under the Plan and its component Programs in the event of the death of a Participant prior to the distribution of all benefits to which he or she is entitled.

2.6

"Code" means the Internal Revenue Code of 1986 and amendments thereto.  Reference to a section of the Code shall include that section and any comparable section or sections of any future legislation that amends, supplements or supersedes said section.

2.7“Committee” means the Management Performance Committee of Questar Corporation.

2.8

"Common Stock" means the no par value common stock of the Company.

2.9

"Company" means Questar Corporation, a corporation organized and existing under the laws of the State of Utah, or its successor or successors.

2.10

"Compensation" means:

(a)

Deferred Compensation Program.  With respect to the Deferred Compensation Program an Employee's salary or wages and payments under incentive compensation plans paid by the Employer and includable in taxable income during the applicable Plan Year, but exclusive of any other forms of additional compensation such as the Employer's cost for any public or private employee benefit plan, any income recognized by the employee as a result of exercising stock options, moving expenses, the value of restricted stock granted after January 1, 2003, as signing or retention bonuses and any dividends paid on such shares, loan forgiveness, welfare benefits, and severance payments.  An Employee's Compensation for any Plan Year shall include any Elective Deferrals of the Employee under the Company's Investment Plan or other tax-qualified plans, as well as any Deferral Contributions made to this Plan.  An Employee's Compensation also shall include the amount of any reduction in Compensation for a

3

Plan Year agreed upon under one or more Compensation reduction agreements entered into pursuant to the Questar Corporation Cafeteria Plan and any pre-tax parking payments that are not includable in the gross income of any Employee by reason of Section 132 (f)(4) of the Code.

(b)

401(k) Supplemental Program.  For purposes of the 401(k) Supplemental Program, Compensation shall have the same meaning as in paragraph (a), above, except that it shall not include any Deferral Contributions made to the Deferred Compensation Program.

2.11

“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.

2.12

“Deferral Contributions” means that portion of a Participant’s Compensation that is deferred by a Participant pursuant to the Programs.

2.13

“Deferred Compensation Program” means the component benefit program of this Plan attached hereto as Appendix A.

2.14

“Deferred Compensation Sub-Account” means the sub-account described in Section 5.1 of the Deferred Compensation Program.

2.15

"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.

2.16

“Effective Date” means January 1, 2005.

2.17

“Eligible Employee” means any Employee that meets the eligibility requirements of Section 3.1.

2.18

"Employee" means any individual that is among a select group of management or highly compensated employees of an Employer.

2.19

"Employer" means the Company and each Affiliated Company that consents to the adoption of the Plan.

2.20

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

2.21

"Fair Market Value" means the closing benchmark price of the Company's Common Stock as reported on the composite tape of the New York Stock Exchange for any given valuation date, or if such date is not a trading day, the next preceding trading day.

2.22

“Investment Plan” means the Questar Corporation Employee Investment Plan, as amended from time to time, or any successor plan.

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2.23

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

2.24

“Key Employee Distribution Date” means the date that is six (6) months after the date of a Key Employee’s Separation from Service.

2.25

“Matching Contributions” means Employer contribution amounts credited to Participants under the Deferred Compensation Program and 401(k) Supplemental Program in addition to (and made on account of) the Participants’ Deferral Contributions under such Programs.

2.26

“Matching Contribution Sub-Account” means the sub-account described in Section 5.1 of the Deferred Compensation Program.

2.27

"Participant" means any individual who has commenced participation in the Plan and its component Programs in accordance with Article 3.

2.28

“Participating Deferral Sub-Account” means the sub-account described in Section 5.1 of the Deferred Compensation Program.

2.29

"Plan" or “Wrap Plan” has the meaning set forth in Section 1.1.

2.30

"Plan Year" means the fiscal year of the Plan, which shall be the calendar year.

2.31

“Predecessor Plans” has the meaning set forth in Section 1.3.

2.32

“Program” means the Deferred Compensation Program and the 401(k) Supplemental Program, or either of them, as the context may require.

2.33

“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.

ARTICLE 3

ELIGIBILITY; PARTICIPATION

3.1

Eligibility.  Eligibility to participate in the Plan shall be determined as follows:

(a)

Any Employee who was an active participant in any of the Predecessor Plans as of December 31, 2004 shall be eligible to participate in this Plan and all of its component Programs as of the Effective Date.  

(b)

Any Employee who was not an active participant in any of the Predecessor Plans as of December 31, 2004 shall become eligible to participate in this Plan on the earliest to occur of:

5

(i)

the date the Employee first becomes an officer of an Employer, in which case the Employee shall be immediately eligible to participate in the 401(k) Supplemental Program and is eligible to participate in the Deferred Compensation Program beginning the first day of the next Plan Year.

(ii)

the date the Employee first receives Compensation in any Plan Year equal to the Compensation Limit, in which case the Employee shall be eligible immediately to participate in the 401(k) Supplemental Program, but shall not be eligible to participate in the Deferred Compensation Program until the first day of the next Plan Year.

(iii)

the date selected by the Committee for the Employee to be eligible to participate in the Plan, in which case the Employee shall be eligible to participate in all of the Plan’s component Programs as of the date selected by the Committee.  If such Employee is not an officer of an Employer or has not received Compensation in any Plan Year equal to the Compensation Limit, then such Employee must be nominated by his or her Employer as eligible to participate in the Plan and approved by the Committee.  

3.2

Enrollment and Commencement of Deferrals.  Except as provided below with regard to automatic enrollment in the 401(k) Supplemental Program, each new Eligible Employee who wishes to make Deferral Contributions must timely complete, execute, and return to the Committee such election forms or other enrollment materials as the Committee requires.  Such enrollment requirements must be completed:

(a) in the case of an Eligible Employee who first becomes eligible to participate as of the first day of a Plan Year, on or prior to December 31^st of the prior Plan Year or such other earlier date as the Committee establishes in its sole and absolute discretion.

(b) in the case of an Eligible Employee who first becomes eligible to participate after the first day of a Plan Year, within thirty (30) days after the date the Eligible Employee first becomes eligible to participate, or such other earlier date as the Committee establishes in its sole and absolute discretion.

If an Eligible Employee fails to timely complete the election forms or other enrollment materials, the Eligible Employee shall be automatically enrolled in the 401(k) Supplemental Program in accordance with the deemed deferral elections set forth in Section 4, but shall not be enrolled in the Deferred Compensation Program until the first day of the first Plan Year beginning after the date he or she completes and returns the enrollment materials to the Committee.

3.3

Failure of Eligibility.  If the Committee determines, in its sole and absolute discretion, that any Participant 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 contributions to the Plan by or on behalf of the Participant shall cease.  The Committee’s determination shall be final and binding on all persons.  

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ARTICLE 4

ELECTIONS

4.1

Elections, General

(a)

First Year of Plan Participation.  In connection with a Participant's enrollment in the Plan pursuant to Section 3.2, the Participant shall make an irrevocable election to defer (or not to defer) Compensation in accordance with the terms of the component Programs for which he is eligible, which election shall apply to the year in which the Participant commences participation.  Such election shall apply solely to Compensation to be paid with respect to services performed on or after his or her enrollment, except to the extent permissible under Code Section 409A and guidance thereunder.  The Participant’s deferral election shall continue to apply for all succeeding Plan Years unless and until revoked or modified pursuant to Section 4.1(b), below. If the Participant fails to complete and return timely the enrollment materials in accordance with Section 3.2, then the Part icipant shall be deemed to have elected to make the Deferral Contributions permitted under the 401(k) Supplemental Program.  

In connection with a Participant's enrollment in the Plan pursuant to Section 3.2, the Participant shall also make the following elections with respect to each Program under the Plan:

(i)

Deferred Compensation Program.  If eligible to participate in the Deferred Compensation Program for the year in which the Participant commences participation under the Plan, the Participant shall make an irrevocable election (from the options available under Section 6, below) as to the time and form of payment of any Deferral or Matching Contributions credited to his or her Account Balance under the Deferred Compensation Program for such year (including earnings thereon).  If the Participant fails to make an election as to the time and form of payment, or if the Participant’s election does not meet the requirements of Code Section 409A and related Treasury guidance or regulations, the Participant shall be deemed to have elected to receive a lump sum distribution as soon as legally and administratively practicable following the earliest to occur of the Participant’s (A ) Separation from Service, (B) Disability, or (C) death.  The Participant’s election (or deemed election) shall continue to apply for succeeding years unless and until the election is modified pursuant to Section 4.1(b), below.  Any such modification shall apply prospectively only and shall not apply to Deferral or Matching Contributions previously credited under the Program (or any earning thereon).

(ii)

401(k) Supplemental Program.  The Participant shall make an irrevocable election as to the time and form of payment of all amounts credited to his or her Account Balance under the 401(k) Supplemental Program from the options available under Section 6, below.  Such election shall be irrevocable and shall apply to the Participant’s entire Account Balance under the Program, including all amounts deferred in subsequent Plan Years and any related earnings.  If the Participant fails to make an election as to the time and form of payment, or if the Participant’s election does not meet the requirements of Code Section 409A and related Treasury guidance or regulations, the Participant shall be deemed to have elected to receive a lump sum distribution as soon as legally and administratively practicable following the earliest to occur of the Participant’s (A) Separatio n From Service, (B) Disability, or (C) death.

(b)

Subsequent Plan Years.  For each succeeding Plan Year, the Participant may, prior to December 31^st of the immediately preceding Plan Year (or such earlier deadline as is established by the Committee in its sole discretion):

7

(i)

make an initial deferral election under the Deferred Compensation Program or modify or revoke his or her existing deferral elections under either or both of the Programs.  All such elections shall be made in accordance with the terms of the Programs and shall remain in effect for subsequent Plan Years unless timely revoked or modified by the Participant in accordance with this Section.

(ii)

make an initial election under the Deferred Compensation Program or modify his or her existing election under the Deferred Compensation Program as to the time and form of payment of any future Deferral or Matching Contributions credited to his or her Account Balance under such Program (and related earnings).  Such election shall be made in accordance with the terms of the Deferred Compensation Program and Section 6, below, and shall remain in effect for subsequent Plan Years unless and until timely modified by the Participant in accordance with this Section.  Any such modification shall apply prospectively only and shall not apply to Deferral or Matching Contributions previously credited under the Program (or any earning thereon).

Any election(s) made in accordance with this Section shall be irrevocable; provided, however, that if the Committee requires Participants to make a deferral election for “performance-based compensation” or “compensation subject to a substantial risk of forfeiture” by the deadline(s) described above, it may, in its sole discretion, and in accordance with Code Section 409A and related Treasury guidance or regulations, permit a Participant to subsequently change his or her elections for such Compensation no later than the deadlines established by the Committee pursuant to Section 4.1(c) or 4.1(d), below.

(c)

Performance-Based Compensation.  The Committee may, in its sole discretion, determine that an irrevocable deferral election pertaining to “performance-based compensation” based on services performed over a period of at least twelve (12) months, may be made no later than six (6) months before the end of the performance service period.  “Performance-based compensation” shall be Compensation, the payment or amount of which is contingent on pre-established organizational or individual performance criteria, which satisfies the requirements of Code Section 409A and related Treasury guidance or regulations.  In order to be eligible to make a deferral election for performance-based compensation, a Participant must perform services continuously from a date no later than the date upon which the performance criteria for such Compensation are established thr ough the date upon which the Participant makes a deferral election for such Compensation.  In no event shall an election to defer performance-based compensation be permitted after such Compensation has become both substantially certain to be paid and readily ascertainable.

(d)

Compensation Subject to Risk of Forfeiture.  With respect to compensation (i) to which a Participant has a legally binding right to payment in a subsequent year, and (ii) that is subject to a forfeiture condition requiring the Participant’s continued services for a period of at least twelve (12) months from the date the Participant obtains the legally binding right, the Committee may, in its sole discretion, determine that an irrevocable deferral election for such compensation may be made no later than the 30^th day after the Participant obtains the legally binding right to the compensation, provided that the election is made at least twelve (12) months in advance of the earliest date at which the forfeiture condition could lapse.

4.2

409A Transition Elections.  Notwithstanding the required deadline for the submission of an election as to the time and form of payment (as set forth in Section 4.1), the Committee may, as permitted by Code Section 409A and related Treasury guidance or

8

regulations, provide a limited period in which Participants may make new distribution elections, which limited period shall in all events expire on December 31, 2008.  Any election as to the time and form of payment made in accordance with the requirements established by the Committee, pursuant to this section, shall not be treated as a change in the form or timing of a Participant’s benefit payment for purposes of Code Section 409A or the Plan.

The Committee shall interpret all provisions relating to an election submitted in accordance with this section in a manner that is consistent with Code Section 409A and related Treasury guidance or regulations.  If any distribution election submitted prior to December 31, 2006 in accordance with this section 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 distribution election submitted on or after January 1, 2007 and prior to December 31, 2007 in accordance with this section 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.  If any distribution election submitted on or after January 1, 2008 and prior to December 31, 2008 in accor dance with this section either (i) relates to payments that a Participant would otherwise receive in 2008, or (ii) would cause payments to be made in 2008, such election shall not be effective.  If any distribution election submitted on or after January 1, 2008 and prior to December 31, 2008 in accordance with this section either (i) relates to payments that a Participant would otherwise receive in 2008, or (ii) would cause payments to be made in 2008, such election shall not be effective.

4.3

Election Forms.  All elections shall be made on forms prepared by the Committee and must be dated, signed, and filed with the Company's Vice President of Human Resources in order to be valid.

ARTICLE 5

ACCOUNT STATEMENTS

At least once a year within 60 days after the end of each Plan Year, a statement shall be sent to each Participant listing his or her Account Balance for each Program as of the last day of the Plan Year.  The statement shall also include the Deferral Contributions made by the Participant to each Program for the Plan Year, along with any Matching Contributions credited to the Participant’s Account Balances and the investment gains or losses (including reinvested dividends) credited during the Plan Year.  Such information shall be reflected on a payroll by payroll basis.

ARTICLE 6

DISTRIBUTIONS

6.1

Permissible Times and Forms of Payments.  A Participant may elect to receive his or her Account under the Deferred Compensation Program (or relevant portion thereof), or his or her Account under the 401(k) Supplemental Program at the following times and in the following forms, provided, however, that the Participant’s Account must be distributed in full within five years of the Participant’s Distribution Event set forth below:

(a)

Time of Distribution.  The Participant may elect to receive a distribution on (or as soon thereafter as administratively feasible), or at a designated anniversary date

9

following, the first to occur of a Participant’s Disability, Separation from Service, or death (“Distribution Event”).

(b)

Form of Distribution.  A Participant may elect to receive a distribution of his or her Account (or any relevant portion of his or her Account under the Deferred Compensation Program) in any of the following forms:

(i)

a single lump sum.

(ii)

up to four (4) annual installments.  

6.2

409A Change in Control.  Notwithstanding any election made by the Participant, in the event of a 409A Change in Control, all amounts then credited to the Participant's Account shall be distributed to him in a single lump sum within 60 days following the 409A Change in Control.  

6.3

Calculation of Distributions.

(a)

Lump Sum.  All lump sum distributions shall be based on the value of the Participant’s Account (or the portion thereof being distributed) as of the last day of the calendar month preceding the payment date.  

(b)

Installment Distributions.  Under an installment payout, the Participant's first installment shall be equal to a fraction of the balance credited to his or her Account (or the portion of his or her account to be paid in installments) as of the last day of the calendar month preceding such payment, the numerator of which is one and the denominator of which is the total number of installments selected.  The amount of each subsequent payment shall be a fraction of the balance in the Participant's Account (or the portion of his or her account to be paid in installments) as of the last day of the calendar month preceding each subsequent payment, the numerator of which is one and the denominator of which is the total number of installments elected minus the number of installments previously paid.  

6.4

Key Employees.  In the event a Participant is a Key Employee, distribution on account of the Key Employee’s Separation from Service cannot commence before 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 delayed until the Key Employee Distribution Date and paid on such date or as soon thereafter as is administratively feasible.  This paragraph shall not apply to any payments that would otherwise be (and are) made on or after the Key Employee Distribution Date.

6.5

Method of Payment.  All payments shall be made in cash.  

ARTICLE 7
ADMINISTRATION

7.1

Committee to Administer and Interpret Plan and Component Programs.  The Committee shall administer the Plan and its component Programs and shall have all discretion and power necessary for that purpose.  The Committee shall have the discretion, authority, and

10

power to (i) make, amend, interpret, and enforce all appropriate rules and regulations for the administration of the Plan and its component Programs and (ii) decide or resolve any and all questions as may arise in connection with this Plan and its component Programs, including interpretations of the Plan and its component Programs and determinations of eligibility to participate and to receive distributions under the Plan and its component Programs.  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 Employer, as the case may be.  The Committee shall maintain all records of the Plan and its component Programs.

7.2

Agents.  In the administration of this Plan and its component Programs, 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.

7.3

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 its component Programs and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan and its component Programs.

7.4

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 and its component Programs, except in the case of willful misconduct by the Committee, any of its members, or any such employee.

7.5

Employer Information.  To enable the Committee to perform its functions, the Employer 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.

7.6

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

ARTICLE 8

CLAIMS PROCEDURE

8.1

Filing a Claim.  All claims under this Plan and its component Programs 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 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

8.2

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 or Program provisions on which the denial is based, a description of any additional material or information necessary for the claimant to perfect his or her 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 sect ion 502(a) following 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 8.2(a) above and shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render its decision.

8.3

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.

8.4

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 to exceed sixty (60) days from 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 or Program 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 8.4(a) above and shall indicate the special circumstances requiring the extension and the date by which the Committee expects to render its decision.

8.5

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 to 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).

8.6

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

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ARTICLE 9

AMENDMENT AND TERMINATION OF PLAN

The Board may at any time amend, modify, or terminate this Plan and its component Programs; provided, however, that no such amendment may reduce any Participant’s Account Balances under the Plan or any component Program as it existed prior to the date of such amendment or termination.  Notwithstanding the foregoing, the Company may, in its sole discretion, amend the Plan and its component Programs without the consent of a Participant or his or her Beneficiary (even if such amendment is adverse to their interests and/or benefit under the Plan or its component Programs) to the minimum extent necessary to meet the requirements of Code Section 409A.

ARTICLE 10

MISCELLANEOUS

10.1

Source of Payments.  Each participating Employer will pay all benefits for its Employees arising under this Plan and its component Programs, and all costs, charges and expenses relating to such benefits, out of its general assets.

10.2

No Assignment or Alienation.

(a)

General.  Except as provided in subsection (b) below, the benefits provided for in this Plan and its component Programs 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 benefits provided for in this Plan or its component Programs 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 to distribute to the alternate payee or payees named in the QDRO as directed by the QDRO.

10.3

Beneficiaries.  A Participant shall have the right, in accordance with forms and procedures established by the Committee, to designate one or more beneficiaries to receive some or all amounts payable under each of the component Programs after the Participant’s death.  The Participant need not designate the same Beneficiary for each Program under the Plan.  In the absence of an effective beneficiary designation, all payments shall be made to the beneficiary designated by the Participant (or deemed by law to be designated) under the terms of the Investment Plan.

10.4

No Creation of Rights.  Nothing in this Plan or its component Programs shall confer upon any Participant the right to continue as an Employee of an Employer.  The right of a Participant to receive a cash distribution shall be an unsecured claim against the general assets of his or her Employer.  Nothing contained in this Plan or its component Programs nor any action

13

taken hereunder shall create, or be construed to create, a trust of any kind, or a fiduciary relationship between the Company and the Participants, Beneficiaries, or any other persons.  All Accounts under the Plan and its component Programs shall be maintained for bookkeeping purposes only and shall not represent a claim against specific assets of any Employer.  

10.5

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 its component Programs and the payment of benefits thereunder.

10.6

Payments to Incompetents.  If the Committee determines in its discretion that a benefit under this Plan or any of its component Programs is to be paid to a minor, a person declared incompetent or to a person incapable of handling the 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 and its component Programs for such payment amount.

10.7

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.  

10.8

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.

10.9

Attorney Fees; Interest.  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 in each case interest on any delayed payment at the applicable Federal rate provided for in Section 7872(f)(2)(A) of the Code.  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 jur isdiction to be frivolous or vexatious.

10.10

Distribution in the Event of Taxation.  If, for any reason, all or any portion of a Participant’s benefits under this Plan or any of its component Programs becomes subject to federal income tax with respect to the Participant prior to receipt, a Participant may petition the Committee for a distribution of that portion of his or her benefit that has become taxable, or such lesser amount as may be permitted by Section 409A.  Upon the grant of such a petition, which grant shall not be unreasonably withheld, the Employer shall distribute to the Participant

14

immediately available funds in an amount equal to the taxable portion of his or her benefit or such lesser amount as may be permitted by Section 409A (which amount shall not exceed a Participant’s unpaid Account Balances).  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 and its component Programs.  Any distribution under this Section 10.10 must meet the requirements of Section 409A and related Treasury guidance or Regulations.

10.11

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

Dated this ______ day of ______________, 2008.

QUESTAR CORPORATION

By:_______________________________________

Keith O. Rattie

Chairman, President & CEO

15

Exhibit A

DEFERRED COMPENSATION PROGRAM

a component Program of the

Questar Corporation  Deferred Compensation Wrap Plan

16

QUESTAR CORPORATION

DEFERRED COMPENSATION PROGRAM

ARTICLE 1

INTRODUCTION

1.1

Establishment of Program.  The Company hereby establishes this Deferred Compensation Program under the Wrap Plan, effective as of January 1, 2005.  The Deferred Compensation Program is designed to replace both the Company’s frozen Deferred Compensation Plan and Deferred Share Plan, and any amounts previously credited under the Deferred Share Plan that remain unvested after December 31, 2004 shall be accounted for under the terms of this Program.

1.2

Purpose.  The purposes of this Program are (i) to provide eligible Employees with the opportunity to defer receipt of up to a specified portion of their annual Compensation in order to reduce current taxable income and to provide for future retirement needs, and (ii) to provide a benefit to each Participant approximately equal to the benefit he would have received under the Investment Plan if the Participant did not elect to defer Compensation under this Program but instead contributed an applicable portion of such amount to the Investment Plan.

ARTICLE 2

PARTICIPATION; ELECTIONS

2.1

Participation.  Each Eligible Employee shall participate in the Deferred Compensation Program at the time set forth in Article 3 of the Wrap Plan.

2.2

Elections.  Each Participant shall make elections with regard to the deferral of Compensation and the time and form of payments under the Program in accordance with Article 4 of the Wrap Plan.

ARTICLE 3

DEFERRAL CONTRIBUTIONS

Each Plan Year, a Participant, if choosing to defer Compensation under the Program for such Plan Year, must defer a minimum of $5,000 and may defer up to a maximum of 50% of his or her Plan Year Compensation.

ARTICLE 4

MATCHING CONTRIBUTIONS

4.1

Amount of Matching Contributions.  A Participant who makes Deferral Contributions to this Program for a Plan Year shall be entitled to a Matching Contribution on six percent of the Deferral Contributions for that Plan Year.  The Matching Contribution shall be determined on the same basis as matching contributions are determined for the Investment Plan for that Plan Year and substituting the Deferral Contributions made pursuant to this Program as the Participant’s “Compensation” under the Investment Plan.

17

4.2

Vesting.  A Participant shall be vested in the portion of his or her Account attributable to Matching Contributions to the same extent as such Participant is vested in any matching contributions under the Investment Plan.

ARTICLE 5

ACCOUNTS; DEEMED INVESTMENTS

5.1

Accounts.  The Committee shall establish an Account for each Participant with at least three sub-accounts as follows:

(a)

a Deferred Compensation Sub-Account which shall reflect all annual Deferral Contributions made by the Participant, minus amounts placed in the Participating Deferral Sub-Account, together with any adjustments for income, gain or loss and any payments from such sub-account as provided herein;

(b)

a Participating Deferral Sub-Account which shall reflect the portion of the annual Deferral Contributions made by the Participant for which the Participant receives a Matching Contribution under this Program, together with any adjustments for income, gain or loss and any payments from such sub-account as provided herein; and

(c)

a Matching Contribution Sub-Account which shall reflect all Company Matching Contributions made under the Program, together with any adjustments for income, gain or loss and any payments from such sub-account as provided herein.

The Committee shall establish such other sub-accounts as it deems necessary or desirable for the proper administration of this Program.  Amounts deferred by a Participant under this Program shall be credited to the Participant’s Account and relevant sub-account as soon as administratively practicable after the amounts would have otherwise been paid to the Participant.

5.2

Status of Accounts.  Accounts and sub-accounts established hereunder shall be  record-keeping devices utilized for the sole purpose of determining benefits payable under this Program, and will not constitute a separate fund of assets but shall continue for all purposes to be part of the general, unrestricted assets of the Employer, subject to the claims of its general creditors.

5.3

Deemed Investment of Amounts Deferred.  

(a)

Participating Deferral and Matching Contribution Sub-Account.  The Participant’s Participating Deferral and Matching Contribution Sub-Account shall be deemed invested in shares of Common Stock purchased at Fair Market Value on the date(s) on which the Deferral Contributions or Matching Contributions are credited to the Participant’s Account.  In addition, the Participant's Participating Deferral and Matching Contribution Sub-Account shall be credited on a quarterly basis with an amount equal to the dividends that would have become payable during the deferral period if actual purchases of Common Stock had been made, with such dividends accounted for as if invested in Common Stock as of the payable date for such dividends.  Any credited shares treated as if they were purchased with dividends shall be deemed to have been purchased at Fair Market Value on the dividend payment date.

18

(b)

Deferred Compensation Sub-Account. In connection with his or her enrollment in the Program, a Participant may elect to have earnings, gains, or losses with respect to his or her Deferred Compensation Sub-Account calculated based on the deemed investment alternatives below, in increments of 25%, 50%, 75%, or 100%.  In the event the Participant fails to make an election regarding the deemed investment of his or her Deferred Compensation Sub-Account, the Participant shall be deemed to have elected to invest 100% of his or her Deferred Compensation Sub-Account in the Common Stock Option (as described below).  The Participant’s investment election shall continue in effect unless and until modified by the Participant.  Any such modification shall apply prospectively only and shall not apply to amounts previously deferred under this Program (and related earnings).  Any such modification must be made effective as of the first day of a Plan Year, and must be made prior to the first day of such Plan Year.

(a)

Common Stock Option.  Any portion of the Deferred Compensation Sub-Account deemed invested under this option (the “Common Stock Option”) shall be accounted for as if invested in shares of Common Stock purchased at Fair Market Value on the date on which a Deferral Contribution is credited to the Participant’s Account.  The Participant's Deferred Compensation Sub-Account shall be credited on a quarterly basis with an amount equal to the dividends that would have become payable during the deferral period if actual purchases of Common Stock had been made, with such dividends accounted for as if invested in Common Stock as of the payable date for such dividends.  Any credited shares treated as if they were purchased with dividends shall be deemed to have been purchased at Fair Market Value on the dividend payment date.

(b)

Treasury Note Option.  Any portion of the Deferred Compensation Sub-Account deemed invested under this option (the “Treasury Note Option”) shall be credited with interest at a monthly rate calculated by dividing by 12 the sum of 100 basis points plus the rate for the appropriate 10-Year Treasury Note as quoted in the Wall Street Journal under “Consumer Savings Rates” on the Thursday closest to the end of the month or other published source of such rates as identified by Questar Corporation’s Treasury department.  The appropriate 10-Year Treasury Note shall be the Note that is the closest (in terms of months) to the date on which the interest is credited.  The interest deemed to be credited to each Deferred Compensation Sub-Account shall be based on the amount credited to such Account at the beginning of each particular month.

ARTICLE 6

DISTRIBUTIONS

All distributions of a Participant’s Account under this Program shall be made in accordance with the Participant’s election(s) (or deemed election(s)) under Article 4 of the Wrap Plan.

19

Exhibit B

401(k) SUPPLEMENTAL PROGRAM

a component Program of the

Questar Corporation  Deferred Compensation Wrap Plan

20

QUESTAR CORPORATION

401(k) SUPPLEMENTAL PROGRAM

ARTICLE 1

INTRODUCTION

1.1

Establishment of Program.  The Company hereby establishes this 401(k) Supplemental Program under the Wrap Plan, effective as of January 1, 2005.  The 401(k) Supplemental Program is designed to replace the Company’s frozen Deferred Share Make-Up Plan, and any amounts previously deferred or credited under the Deferred Share Make-Up Plan that remain unvested after December 31, 2004 shall be accounted for under the terms of this Program.

1.2

Purpose.  The purpose of this supplemental Program is to provide a benefit to an Employee approximately equal to the benefit he would have received under the Investment Plan if the Compensation Limit were inapplicable.

ARTICLE 2

PARTICIPATION; ELECTIONS

2.1

Participation.  Each Eligible Employee shall participate in the 401(k) Supplemental Program at the time set forth in Article 3 of the Wrap Plan.

2.2

Elections.  Each Participant shall make elections with regard to the deferral of Compensation and the time and form of payments under this Program in accordance with Article 4 of the Wrap Plan.

ARTICLE 3

DEFERRAL CONTRIBUTIONS

Each Plan Year, a Participant choosing to defer Compensation under this Program must defer 6% of his or her Plan Year Compensation in excess of the Compensation Limit.

ARTICLE 4

MATCHING CONTRIBUTIONS

4.1

Amount of Matching Contributions.  A Participant who makes Deferral Contributions to this Program for a Plan Year shall be entitled to a Matching Contribution for such Plan Year in an amount determined on the same basis as matching contributions are determined for the Investment Plan, except that such Matching Contribution shall be based solely on Compensation in excess of the Compensation Limit.

4.2

Vesting.  A Participant shall be vested in the portion of his or her Account attributable to Matching Contributions to the same extent as such Participant is vested in any matching contributions under the Investment Plan.

21

ARTICLE 5

ACCOUNTS; DEEMED INVESTMENTS

5.1

Accounts.  The Committee shall establish an Account and sub-accounts for each Participant as are necessary for the proper administration of this 401(k) Supplemental Program.  Such Accounts shall reflect Deferrals Contributions and Matching Contributions made by or on behalf of the Participant, together with any adjustments for income, gain or loss and any payments from the Account as provided herein.  Deferral Contributions and related Matching Contributions shall be credited to the Participant’s Account as soon as administratively practicable after the Deferral Contribution would have otherwise been paid to the Participant.  

5.2

Status of Accounts.  Accounts and sub-accounts established hereunder shall be  record-keeping devices utilized for the sole purpose of determining benefits payable under this Program, and will not constitute a separate fund of assets but shall continue for all purposes to be part of the general, unrestricted assets of the Employer, subject to the claims of its general creditors.  

5.3

Deemed Investment in Company Stock.  The Participant’s Account shall be deemed invested in shares of Common Stock purchased at Fair Market Value on the date(s) on which the Deferral Contributions or Matching Contributions are credited to the Participant’s Account.  In addition, the Participant's Account shall be credited on a quarterly basis with an amount equal to the dividends that would have become payable during the deferral period if actual purchases of Common Stock had been made, with such dividends accounted for as if invested in Common Stock as of the payable date for such dividends.  Any credited shares treated as if they were purchased with dividends shall be deemed to have been purchased at Fair Market Value on the dividend payment date.

ARTICLE 6

DISTRIBUTIONS

All distributions of a Participant’s Account under this Program shall be made in accordance with the Participant’s election(s) (or deemed election(s)) under Article 4 of the Wrap Plan.

22

EX-12

Exhibit 12.

Questar Corporation

Ratio of Earnings to Fixed Charges

	Year Ended December 31,
	2008	2007	2006
	(dollars in millions)
Earnings
Income before income taxes	$1,061.8	$798.0	$699.6
Less company’s share of earnings of
equity investees	(2.3)	(8.9)	(7.5)
Plus distributions from equity investees	0.5	10.4	7.1
Plus interest expense	119.5	72.2	73.6
Plus capitalized interest	6.1	8.0	0.8
Plus interest portion of rental expense	4.7	3.7	3.1
	$1,190.3	$883.4	$776.7
Fixed Charges
Interest expense	$  119.5	$  72.2	$  73.6
Plus capitalized interest	6.1	8.0	0.8
Plus interest portion of rental expense	4.7	3.7	3.1
	$ 130.3	$  83.9	$  77.5
Ratio of Earnings to Fixed Charges	9.1	10.5	10.0

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-14

Exhibit 14.

Questar Corporation Business Ethics and Compliance Policy

A Message from Keith Rattie

 “Questar’s reputation for integrity and honesty is more important today than ever.  It’s a source of competitive advantage – one that we want to preserve.”

 – Keith O. Rattie, Questar CHAIRMAN, PRESIDENT and CEO

TABLE OF CONTENTS

A.

Employment Practices

B.

Business, Accounting and Disclosure Practices

C.

Conflicts of Interest

D.

Gifts

E.

Confidential Information

F.

Antitrust Awareness

G.

Environmental Affairs and Safety

H.

Dealings with the Media and Securities Market Professionals

I.

Political Activity

J.

Internet, E-mail, Telephone and Voice Mail Usage

K.

Compliance Procedures

As a Questar employee, you are required to:

• Know and comply with this Business Ethics and Compliance Policy;

• Comply with all applicable laws, rules and regulations in the performance of your duties for Questar;

• Be aware of situations that could lead to inappropriate business conduct and avoid engaging in such conduct;

• Promptly notify Questar management of any suspected breach of this Policy or other illegal behavior; and

• Always conduct business with honesty and integrity.

Anyone violating the Business Ethics and Compliance Policy will be subject to disciplinary action up to and including termination.

To report a suspected violation of this policy, contact one of the following:

Ethics Help Line

800-892-2050 or 801-324-2050 (available 24/7)

Vice President, Compliance:

 801-324-5678

General Counsel:

801-324-2648

No employee will be subject to retaliation, discrimination, or any other adverse employment action for reporting suspected violations in good faith pursuant to the terms of this Policy or any applicable law.

Questar generally does not approve waivers of this policy.  However, if a waiver is warranted, only the CEO of the business unit or the Chairman, President and CEO of Questar Corporation may grant one.  Any waiver for executive officers may be made only by the Board of Directors and will be disclosed to shareholders.

A.

EMPLOYMENT PRACTICES

Questar’s success is based on a business culture that promotes mutual respect for the rights and dignity of all employees. We must maintain an atmosphere of fairness and integrity. Questar values the unique contributions of people with different traits and backgrounds and is committed to providing a workplace that encourages inclusion.

1.

EQUAL EMPLOYMENT OPPORTUNITY.  Questar will provide equal opportunity to applicants and employees in the areas of hiring, training, promotion and compensation without regard to race, religion, age, gender, disability, veteran status or national origin.  All employees are entitled to work and participate in employer-sponsored activities in an environment free of sexual, ethnic and religious harassment, hostility or intimidation. Questar's policies require compliance with all state or federal anti-discrimination laws.  The Human Resources staff can provide guidance for dealing with questions or concerns about discrimination or harassment.

2.

SUBSTANCE ABUSE.  Questar prohibits employees from using illegal drugs and misusing prescription drugs.  Questar has a substance-abuse policy and expects all employees to perform their duties unimpaired by drugs or alcohol and to participate in drug and alcohol testing in accordance with that policy.

B.

BUSINESS, ACCOUNTING AND DISCLOSURE PRACTICES

1.

All Questar business records must be truthful and accurate and comply with applicable accounting standards and rules and established internal controls.  There may be no payments of money, property transfers, furnishing of services or other transactions on behalf of Questar without adequate supporting documentation. Employees must protect Company assets from waste, carelessness and theft and ensure that those assets are used only for legitimate business purposes. Questar prohibits use of Company assets for any unlawful or improper purpose.  If you become aware of any falsification, inaccuracy or omission in Questar’s business records or the information supporting those records, immediately bring the matter to the attention of management by using the Compliance Procedures described in Section K of this Policy.

2.

Each employee, officer and director should deal fairly with the Company’s customers, suppliers, competitors and employees.  They should not take advantage of anyone through manipulation, concealment, abuse of confidential information, misrepresentation of material facts or any other unfair dealing.

C.

CONFLICTS OF INTEREST

1.

Conflicts of interest exist when employees are faced with situations that require choosing between Questar's best interests and their own interests, or when the employee's judgment may be compromised by doing something that may be favorable to the Company but would also benefit the employee personally. To protect the Company's interests, employees and their family and household members, as a general rule, must avoid involvement, financial or otherwise, in other organizations and situations in which a conflict of interest exists, could exist, or may appear to exist.

Q:   I participate in Questar’s bid evaluations for construction jobs. My brother owns a construction company that bid on a Questar project. Can I participate in the bid evaluation?

A:   No.  You should not take part in the decision about which construction company to use.  While you may be fair in the evaluation, it might appear as though the relationship with your brother influenced your decision.

2.

No employee, without prior written approval of the corporate Chairman, President and CEO, may serve as a director, in any managerial capacity, or as an employee or agent of any firm that is a competitor of the Company, a purchaser of products (other than retail natural gas) of the Company, or a consistent or substantial seller of products or services to the Company.  Employees and their family and household members are prohibited from speculating in materials, equipment, supplies or property to be purchased by a Questar company based upon information not available to the general public.

3.

Loans by the Company to executive officers and directors represent potential conflicts of interest and are generally prohibited.  

4.

Employees and directors may not take personal advantage of any business opportunity that properly belongs to Questar.

5.

Employees may not engage in outside interests that interfere with the time or attention required to attend to Company business or that affect their ability to perform their duties without express supervisory approval.

Q:   I have been asked to serve as a member of the board of a local charity.  It is a volunteer position that will not conflict with my Questar responsibilities.  Do I have to inform Management?

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COMPLIANCE\POLICIES\BUS ETHICS COMPL POLICY 2008.DOC

A:   No.  If the position does not involve a for-profit company, does not require use of Questar’s time, resources or the Questar name, and does not otherwise conflict with your job duties at Questar, you are not obligated to report your position with the charity to Management.

6.

If an employee or his or her family or household members has a potential conflict of interest, the employee should disclose the personal interest to the Vice President, Compliance, or General Counsel.  This disclosure should include a description of the proposed activity or transaction and the dollar amount involved.  If a conflict appears to exist, further disclosure must be made in writing to the corporate Chairman, President and CEO and the business-unit president who will decide whether to grant a waiver of the Policy.

7.

Employees may not, except after proper disclosure and with approval of the President and CEO of Questar Market Resources, own or acquire, or cause others to own or acquire, oil and gas mineral interests, leases, working or royalty interests; energy reserves; energy-futures contracts; or options for energy commodities.  Employees should disclose ownership of such interests at the time they are hired (or in a timely manner if later acquired by inheritance).

8.

Employees in sensitive positions should exercise caution when investing in entities with which Questar has confidential or close business relationships or in entities in which Questar itself has taken or could take an ownership position.

D.

GIFTS

As a Questar employee, you may not give or accept money, loans, expensive gifts or services, extravagant entertainment, travel, or preferential treatment for any services related to your job. You may accept conventional business courtesies, such as lunches, where a similar favor can be returned.  You may also accept business entertainment that involves representatives of other companies as well as Questar if no expensive or questionable gifts, goods or travel are included.  The corporate Chairman, President and CEO or business-unit presidents should determine the propriety of accepting these gifts or invitations.   

Q:   A contractor who does work for Questar sent me an MP-3 player as a holiday gift. May I accept it?

A:   No.  An MP-3 player qualifies as an expensive gift that an employee may not accept. If you are not comfortable sending it back to the contractor, you may turn it over to the Community Affairs director for use in Questar charitable or incentive projects.

E.

CONFIDENTIAL INFORMATION

1.

CONFIDENTIALITY.  As a Questar employee you have access to confidential information.  Any information concerning Questar that is not generally available to others is confidential.  The improper disclosure of confidential information could negatively impact Questar.  In addition to violating Questar policy, unauthorized use of confidential information may be a criminal offense and subject the employee to fines and/or imprisonment.  As an employee, you have an obligation to prevent unauthorized disclosure of Questar’s confidential information.  Except as authorized or directed by their business-unit  president, employees shall not, during or after their employment with Questar, divulge any confidential or proprietary information about a Questar company or third parties obtained during their employment with Questar.

Customer information and confidential employee information in Company files may not be disclosed outside the Company without the Company's and the customer’s or employee’s permission, except in response to a subpoena, other legal process or requests from government investigatory or regulatory agencies, as approved by the legal department.  This information should not be disseminated within the Company unless it is required for a valid business purpose.

2.

INSIDER TRADING.  To protect Questar’s investors and comply with applicable laws, employees may not trade Questar stock while possessing “inside information” (material information not known or disclosed to the public in general).  Severe penalties can be imposed for illegal insider-trading violations.  In addition, Questar employees may not advise any other person to trade or refrain from trading Company stock on the basis of inside information.  Any questions regarding this Policy should be directed to Questar's General Counsel or Vice President, Compliance.

Q:   I recently learned some information about a well that has not been disclosed to the public. Am I prohibited from buying or selling Company stock?

A:   Yes, if the information you learned is material.  Material information is information that an investor would consider in deciding whether to buy, sell or hold Questar stock.  If the information is material, you may not buy or sell Questar stock on the open market until two business days after the information becomes public.  If you have any questions about whether the information is material, please contact the Company’s General Counsel or Vice President, Compliance.

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COMPLIANCE\POLICIES\BUS ETHICS COMPL POLICY 2008.DOC

4.

OWNERSHIP OF NEW IDEAS AND PRODUCTS.  Any ideas, products or services developed by an employee while working for Questar with the aid of Company resources such as materials, facilities or on Company time become the exclusive property of Questar.

5.

FERC RULES.  Questar Transmission Provider employees (Questar Pipeline Company, Overthrust Pipeline Company, Questar Southern Trails Pipeline, Rendezvous Pipeline Company and Clear Creek Storage) engaged in transmission system operations must function independently from employees of its Marketing Affiliates.

Questar Transmission Provider employees must treat all transmission customers, affiliated and non-affiliated, on a non-discriminatory basis, and must not operate its transmission system to preferentially benefit its Marketing Affiliates.

FERC rules prohibit Questar employees from sharing or acting as conduits in providing, certain transmission-system information with unauthorized parties unless that information has first been made public through FERC-approved methods (i.e., the Transmission Provider’s Internet Web site).

Questar is committed to complying with all FERC rules and regulations.  Any employee who is aware of a FERC compliance rule and/or regulation violation, believes that a violation may have occurred, or has a question relating to FERC compliance, should immediately contact the Chief FERC Compliance Officer (801-324-2543) or Questar's Ethics Help Line (800-892-2050 or 801-324-2050).

F.

ANTITRUST AWARENESS

Questar and its affiliated companies compete vigorously but fairly and in compliance with all applicable antitrust laws and regulations.  Antitrust laws forbid, among other things, price fixing.  Questar companies must make their pricing decisions independent of competitors.  The exchange of sensitive information with competitors such as product prices, profit margins, billing practices, or other information that might facilitate reaching an agreement on prices, can pose substantial risk under the antitrust laws.  Employees are prohibited from discussing with competitors, including trade association members, non-public information covering the following topics: pricing policies, discounts, profits, credit terms, other conditions of the sale of goods or services, geographic areas of operation or sales, production or sales quotas, customer allocations, bids for jobs or contracts and other similar information.  

Other activities prohibited by the antitrust laws include:  unlawful tying, unlawful exclusivity agreements, monopolization, market and consumer allocation, group boycotts/refusals to deal, resale price maintenance, unlawful termination of dealers/suppliers/distributors and other such conduct.

Violations of the antitrust laws can result in both criminal and civil penalties. Contact either the Vice President, Compliance or the General Counsel if you have any questions about antitrust laws.

G.

ENVIRONMENTAL AFFAIRS AND SAFETY

1.

Questar is committed to full compliance with all applicable environmental laws and regulations.  Company policies and procedures reflect this goal. As an employee, your work practices must comply with these laws and regulations. If you have questions whether your actions, or proposed actions, conflict with environmental regulations, contact the legal department.

2.

Questar's workplaces must comply with safety and health standards and be free of recognized hazards that could cause injury, sickness or death.  Employees should carry out their duties in a safe and efficient manner.  To eliminate potential hazards, employees must immediately report unsafe conditions and immediately correct unsafe acts or conditions.  No employee will be subject to retaliation, discrimination, or any other adverse employment action for reporting concerns about safety or environmental problems.  Supervisors and employees must report any work-related injury or sickness promptly as specified in Company policies.

H.

DEALINGS WITH THE MEDIA AND SECURITIES MARKET PROFESSIONALS

1.

MEDIA RELATIONS.  Comments to the news media should be made only by designated spokespersons.  Employees should direct all media inquiries to the appropriate corporate or business-unit communication department.

Q:   A reporter called me looking for some basic information about the Company. Can I answer her question?

A:   No. Even simple questions should be routed to the appropriate media contacts within the business units.  One problem with individual employees releasing information is that they may not have all of the facts.  Additionally, the premature release of information may create problems with securities laws, or it may put the Company at a competitive disadvantage.

2.

CONTACT WITH SECURITIES MARKET PROFESSIONALS.  The only individuals who are authorized to speak on behalf of the Company to securities analysts, broker-dealers, security holders and other securities market professionals, or holders of the issuer’s securities who may trade on the basis of the information are:  the corporate

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COMPLIANCE\POLICIES\BUS ETHICS COMPL POLICY 2008.DOC

Chairman, President and CEO; the President and CEO of Questar Market Resources, Inc.; the President and CEO of Questar Gas Company; the President and CEO of Questar Pipeline Company; the Chief Financial Officer; and the Treasurer.  Other employees must direct inquiries to the Investor Relations Department and must not attempt to handle these inquiries without prior authorization from the Investor Relations Department (801-324-5077).

3.

MESSAGE BOARDS.  Employees are not permitted to post potentially sensitive or proprietary Company information on Internet message boards.  In addition to Company discipline, such activity could result in criminal and/or civil fines and penalties.

I.

POLITICAL ACTIVITY

1.

RELATIONSHIPS. Questar strives to develop and maintain good relationships and effective communication with government officials and agencies.  Dealings with government and regulatory agencies must be consistent with Questar's reputation for high integrity.  Business-unit presidents are responsible for developing the "Company position" on relevant legislation and regulatory proposals.  

The Company encourages political activity and participation in politics where appropriate.  However, such activity must occur strictly in an individual and private capacity and not on behalf of the Company, unless specifically authorized by the corporate Chairman, President and CEO or the business-unit president.  Employees may not conduct personal political activity on Company time or use Company property, equipment or stationery for this purpose.

2.

CANDIDATE SELECTION. Questar is nonpartisan with respect to supporting candidates for public office. To ensure compliance with this Policy, Questar’s Board of Directors reviews and approves the use of all corporate funds or assets intended to influence the nomination or election of any candidate for public office.

This prohibition does not apply to personal political activity, personal contributions made to candidates or to political parties. Questar encourages all employees to participate in the local, state and national political processes.

3.

QUESTAR PAC. The Company established the Questar Corporation Political Action Committee and various state political action committees. Membership is strictly voluntary. Personal funds contributed to the committee(s) are managed by a steering committee that distributes funds to candidates and political causes that further good government and sound fiscal policy and that support positions favorable to Questar.  Contributions are made without regard to political affiliation.

J.

INTERNET, E-MAIL, TELEPHONE AND VOICE-MAIL USAGE  

Employees are subject to the terms of Questar's Electronic and Telephonic Systems Policy.  All messages sent or received through these systems, as well as the contents of personal computers, are considered Company property.  Employees do not have a right of privacy in their use of these resources and are prohibited from using them for sending or accessing communications that constitute obscenity, defamation or harassment.  The improper use of copyrighted materials and excessive computer use for personal purposes are also prohibited.

Q:   My family and friends e-mail me at work, keeping me up-to-date on events and funny stories. These are personal messages; can I expect them to remain private on my Questar computer?

A:   No, although you may use your Questar computer for occasional private purposes, you cannot expect privacy in e-mail received on the computer. Questar owns the computer and all information stored on it and may review that information at any time. Be careful when using e-mail as it creates a permanent electronic record. Avoid using abusive or objectionable language, viewing or sending obscene materials and other inappropriate behaviors.  Always be professional in your language and tone.

K.

COMPLIANCE PROCEDURES

1.

Questar officers are responsible for the enforcement of and compliance with the Questar Business Ethics and Compliance Policy. They will make sure every employee reviews this Policy and receives appropriate training and consultation.

2.

Any employee who knows of a violation of this Policy, or who reasonably believes that a violation has occurred, must promptly report the matter through the Ethics Help Line (1-800-892-2050 or 801-324-2050) or to the Vice President, Compliance, or the General Counsel.  Questar takes all reports of Policy violations very seriously.  You may make anonymous reports on the Ethics Help Line, but they are more difficult to investigate. Questar, to the extent legally possible, will protect the confidentiality of any disclosed information and the identity of any employee reporting misconduct.  No employee will be subject to retaliation, discrimination, or any other adverse employment action for reporting, in good faith, suspected violations of this Policy or any applicable law.  Supervisors should refer employees who advise them about possible violations of this Policy to one of the office rs listed above.

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COMPLIANCE\POLICIES\BUS ETHICS COMPL POLICY 2008.DOC

3.

Employees should talk to the Vice President, Compliance or General Counsel if they have any concerns about whether an activity within the Company is unethical.  Any employee who believes that someone other than these individuals should address the concern may report it to the Chair of Questar's Finance and Audit Committee of the Board of Directors.

4.

Questar officers are required to state in writing each year that they have no knowledge of any material violation of this Policy other than any violations that have been reported.

5.

The Questar internal audit department will periodically review the Company's activities, records, property, and personnel to determine compliance with this Policy.  The results will be reported in writing to executive management and the Finance and Audit Committee.

6.

The Finance and Audit Committee will receive a summary of all business ethics and compliance reports and complaints.  The Finance and Audit Committee has the authority to obtain assistance from internal and external sources to address any concerns.

7.

In reporting on their examination of Questar's financial statements, the Company's independent auditors will be asked to state whether anything has come to their attention that has led them to believe that this Policy is being violated.

8.

Any information received and any investigations concerning such information will be retained consistent with applicable law and Questar's document retention policy.

9.

This Policy is not all-encompassing, and questions about situations not specifically addressed in it should be directed to the Questar Corporation Vice President, Compliance or General Counsel.

10.

This Policy has been approved by the Finance and Audit Committee of Questar's Board of Directors and by executive management.

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COMPLIANCE\POLICIES\BUS ETHICS COMPL POLICY 2008.DOC

EX-21

Exhibit 21.

SUBSIDIARY INFORMATION

Registrant Questar Corporation has the following subsidiaries: Questar Market Resources, Inc., 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 two wholly owned subsidiaries: Questar URC Company, a Delaware corporation and Rippy Energy, Inc., a Texas 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 three subsidiaries: Questar Energy Services, Inc., Questar Project Employee Company, and Questar Applied Technology Services, Inc. All three are Utah corporations.

EX-23

Exhibit 23.1.

Consent of Independent Registered Public Accounting Firm

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 24, 2009, 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

Salt Lake City, Utah  

February 24, 2009

EX-23

Exhibit 23.2.

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, we hereby consent to the reference of our appraisal reports for Questar Exploration and Production Company in the Form 10-K of Questar Corporation and Questar Market Resources, Inc. as of years ended December 31, 2005, 2006, 2007, 2008 incorporated herein by reference into Questar Corporation’s Registration Statements Nos. 33-04436, 33-15149, 33-40800, 33-40801, 33-48169, 333-04913, 333-04951, 333-67658, 333-89486 and 333-09643 on Form S-8.  We also hereby consent to the reference of our appraisal reports for Questar Exploration and Production Company in Questar Market Resources, Inc.’s Registration Statements Nos. 333-149589 and 333-153818 on Form S-3.

/s/Ryder Scott Company, L.P

.

RYDER SCOTT COMPANY, L.P.

Denver, Colorado

February 26, 2009

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 the Form 10-K of Questar Corporation and Questar Market Resources, Inc. with respect to the oil and gas reserves of Questar Exploration and Production Company as of years ended December 31, 2005, 2006, 2007 and 2008. We hereby further consent to all references to our firm included in this Form 10-K. We also further consent to the inclusion of the information included in the Form 10-K with respect to the oil and gas reserves of Questar Exploration and Production Company in Questar Corporation’s Registration Statements Nos. 33-04436, 33-15149, 33-40800, 33-40801, 33-48169, 333-04913, 333-04951, 333-67658, 333-89486, 333-09643 on Form S-8 and Questar Market Resources, Inc.’s Registration Statements Nos. 333-149589 and 333-153818 on Form S-3.

NETHERLAND, SEWELL & ASSOCIATES, INC.

By:  /s/C. H. (Scott) Rees III, P.E.

C. H. (Scott) Rees III, P.E.

Chariman and Chief Executive Officer

Dallas, Texas

February 26, 2009

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 2008 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 2008 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,

02/10/09

Keith O. Rattie

President, and Chief Executive Officer

Director

/s/

Director

02/10/09

Phillips S. Baker, Jr.

/s/

Director

02/10/09

Teresa Beck

/s/

Director

02/10/09

R. D. Cash

/s/

Director

02/10/09

L. Richard Flury

/s/

Director

02/10/09

James A. Harmon

/s/

Director

02/10/09

Robert E. McKee III

/s/

Director

02/10/09

Gary G. Michael

/s/

Director

02/10/09

M. W. Scoggins

/s/

Director

02/10/09

Harris H. Simmons

/s/

Director

02/10/09

C. B. Stanley

/s/

Director

02/10/09

Bruce A. Williamson

EX-31

Exhibit 31.1.

CERTIFICATION

I, Keith O. Rattie, certify that:

1.

I have reviewed this report of Questar Corporation on Form 10-K for the period ended December 31, 2008;

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 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, 2009

/s/ Keith O. Rattie

Keith O. Rattie

Chairman, President and Chief Executive Officer

EX-31

Exhibit 31.2.

CERTIFICATION

I, S. E. Parks, certify that:

1.

I have reviewed this report of Questar Corporation on Form 10-K for the period ended December 31, 2008;

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 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, 2009

/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 this report of Questar Corporation (the Company) on Form 10-K for the period ended December 31, 2008, 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, 2009

/s/Keith O. Rattie

Keith O. Rattie

Chairman, President and Chief Executive Officer

February 26, 2009

/s/S. E. Parks

S. E. Parks

Senior Vice President and Chief Financial Officer