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 contingencies such as legal proceedings, trends in operations and financial results.

Any or all forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are

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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 corporate 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 Questar 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 involves economic assumptions relating to commodity prices, production costs, severance and other taxes, capital expenditures and remedial costs. Actual results most likely will vary from the estimates. Any significant variance could reduce the estimated future net revenues from proved reserves and the present value of those reserves.

Investors should not assume that the “standardized measure of discounted future net cash flows” from Questar E&P’s proved reserves referred to in this Annual Report is the current market value of the estimated natural gas and oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from Questar E&P’s proved reserves is based on prices and costs in effect on the date of the estimate, holding the prices constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the current estimate, and future determinations of the standardized measure of discounted future net cash flows using then current prices and costs may be significantly less than the current estimate.

Shortages of oilfield equipment, services and qualified personnel could impact results of operations. The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and gas industry can fluctuate significantly, often in correlation with 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 Company’s customers. Such circumstances could adversely impact the Company’s ability to meet contractual obligations and retain customers.

As is customary in the gas and oil industry, the Company maintains insurance against some, but not all, of these potential risks and losses. Questar cannot assure that insurance will be adequate to cover these losses or liabilities. Losses and liabilities arising from uninsured or underinsured events could have 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. From time to time the Company may use interest-rate derivatives to fix the rate on a portion of its variable-rate debt. The interest rates on bank loans are tied to debt credit ratings of Questar and its subsidiaries published by Standard & Poor’s and Moody’s. A downgrade of credit ratings could increase the interest cost of debt and decrease future availability of money from banks and other sources. 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 the price of natural gas, restrict access to or the use of natural gas, and/or reduce natural gas demand. Federal, state and local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for natural gas. While future climate-change regulation is likely, it is too early to predict how this regulation will affect 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 that 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 particular regulatory program applicable to those facilities. EPA claims that Gas Management failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations for testing and reporting, among other things. Gas Management contends that its facilities have pollution controls installed that reduce their actual air emissions below major source thresholds, rendering them subject to different regulatory requirements. Gas Management intends to vigorously defend against the EPA’s claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying Utah’s CAA program or EPA's prior practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict the likely potential outcomes; however, management believes the company has accrued an appropriate liability for this claim.

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 December 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 natural 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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26

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 proved 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, multiplied by the relevant volume, for the settlement period.

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

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

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

Bad-debt expense associated with accounts receivable for the year ended December 31, amounted to $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 the 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 recorded 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’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 current booked proved undeveloped reserves.

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

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

	Year Ended December 31,
	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 unauthorized 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.

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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

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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.)

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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.

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(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