UNITED STATES

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Year Ended December 31, 2006

[str10k4q2006001.jpg]

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

STATE OF UTAH 1-8796 87-0407509

(State or other jurisdiction of (Commission File No.) (I.R.S. Employer

incorporation or organization) 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) 324-5000

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

Common stock without par value

The above Securities are listed on the New York Stock Exchange

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

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

Yes [X]

No [ ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes [ ]

No [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

QUESTAR 2006 FORM 10-K 1

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

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

Yes [ ]

No [X]

Aggregate market value of the voting common equity held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second quarter (June 30, 2006): $6.9 billion.*

On January 31, 2007, 85,946,432 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 15, 2007.

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

QUESTAR 2006 FORM 10-K 2

TABLE OF CONTENTS

Page No.

Where You Can Find More Information

Forward-Looking Statements

Glossary of Commonly Used Terms

PART I

Item 1.

BUSINESS

Nature of Business

Market Resources

Questar E&P

Wexpro

Gas Management

Energy Trading

Questar Pipeline

Questar Gas

Corporate and Other Operations

Environmental Matters

Employees

Executive Officers

Item 1A.

RISK FACTORS

Item 1B.

UNRESOLVED STAFF COMMENTS

Item 2.

PROPERTIES

Questar E&P

Wexpro

Gas Management

Energy Trading

Questar Pipeline

Questar Gas

Item 3.

LEGAL PROCEEDINGS

Item 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

PART II

Item 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER

MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Item 6.

SELECTED FINANCIAL DATA

Item 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATION

Item 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

QUESTAR 2006 FORM 10-K 3

ON ACCOUNTING AND FINANCIAL DISCLOSURE

Item 9A.

CONTROLS AND PROCEDURES

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Item 11.

EXECUTIVE COMPENSATION

Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Item 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,

AND DIRECTOR INDEPENDENCE

Item 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

PART IV

Item 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

SIGNATURES

Where You Can Find More Information

Questar Corporation (Questar) and its principal subsidiaries, Questar Market Resources, Inc., Questar Pipeline Company and Questar Gas Company, each file annual, quarterly, and current reports with the Securities and Exchange Commission (SEC). Questar also regularly files proxy statements and other documents with the SEC. The public may read and copy these reports and any other materials filed with the SEC at its Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549-0213. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC also maintains a web site that contains information filed electronically that can be accessed over the Internet at www.sec.gov.

Investors can also access financial and other information via Questar’s web site at www.questar.com. Questar and each of its reporting subsidiaries make available, free of charge through the web site copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to such reports and all reports filed by executive officers and directors under Section 16 of the Exchange Act reporting transactions in Questar securities. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC. Questar’s web site also contains Statements of Responsibility for Board Committees, Corporate Governance Guidelines and its Business Ethics and Compliance Policy.

Finally, you may request a copy of filings other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing or calling Questar, 180 East 100 South Street, P.O. Box 45433, Salt Lake City, Utah 84145-0433 (telephone number (801) 324-5000).

Forward-Looking Statements

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

QUESTAR 2006 FORM 10-K 4

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

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

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

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

changes in industry trends;

changes in laws or regulations; and

other factors, most of which are beyond 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

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.

Btu

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

cash flow hedge

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

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

cfe

Cubic feet of natural gas equivalents.

development well

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

dewpoint

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

dry hole

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

dth

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

dthe

Decatherms of natural gas equivalents.

equity production

Production at the wellhead attributed to Questar ownership.

exploratory well

QUESTAR 2006 FORM 10-K 5

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

finding costs

The sum of costs incurred for gas and oil exploration and development activities; including purchases of reserves in place, leasehold acquisitions, seismic, geological and geophysical, development and exploration drilling and asset retirement obligations for a given period, divided by the total amount of estimated net proved reserves added through discoveries, positive and negative revisions and purchases in place for the same period. The Company expresses finding costs in dollars per Mcfe averaged over a five-year period.

frac spread

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

futures contract

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

gal

U.S. gallon.

gas

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

gross

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

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.

Thousand.

Million.

natural gas equivalents

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

natural gas liquids (NGL)

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

net

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

net revenue interest

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

production replacement ratio

The production replacement ratio is calculated by dividing the net proved reserves added through discoveries, positive and negative revisions and purchases and sales in-place for a given period by the production for the same period, expressed as a percentage. The production replacement ratio is typically reported on an annual basis.

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).

QUESTAR 2006 FORM 10-K 6

proved developed producing reserves

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

proved undeveloped reserves

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

reservoir

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

royalty

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

seismic

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

wet gas

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

working interest

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

workover

Operations on a producing well to restore or increase production.

FORM 10-K

ANNUAL REPORT, 2006

PART I

ITEM 1. BUSINESS.

Nature of Business

Questar Corporation (Questar or the Company) is a natural gas-focused energy company with four major lines of business – gas and oil exploration and production, midstream field services, 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 services.

Questar Gas Company (Questar Gas) provides retail natural gas distribution.

See Note 15 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for financial information concerning Questar’s lines of business that contribute 10% or more of consolidated revenues.

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 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.

QUESTAR 2006 FORM 10-K 7

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.

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

[str10k4q2006003.gif]

Market Resources

Market Resources is a natural gas-focused energy company, a wholly owned subsidiary of Questar and Questar’s primary growth driver. Market Resources is a subholding company with four principal subsidiaries: Questar E&P acquires, explores for, develops and produces natural gas, oil, and NGL; Wexpro manages, develops and produces cost-of-service reserves for affiliate Questar Gas; Gas Management provides midstream field services including natural gas-gathering and processing services for affiliates and third parties; and Energy Trading markets equity and third-party gas and oil, provides risk-management services, and through its wholly owned limited liability company, Clear Creek Storage Company, LLC, owns and operates an underground natural gas-storage reservoir.

Questar E&P

Questar E&P operates in two core areas – the Rocky Mountain region of Wyoming, Utah and Colorado and the Midcontinent region of Oklahoma, Texas and Louisiana. Questar E&P has a large inventory of identified development drilling locations, primarily on the Pinedale Anticline in western Wyoming, in the Uinta Basin of Utah and in the Elm Grove area of northwestern Louisiana. Questar E&P continues to conduct exploratory drilling to determine the commerciality of its inventory of undeveloped leaseholds located primarily in the Rocky Mountain region. Questar E&P seeks to maintain geographical and geological diversity with its two core areas. Questar E&P has in the past and may in the future pursue acquisition of producing properties through the purchase of assets or corporate entities to expand its presence in its core areas or create a new core area.

Questar E&P reported 1,631.4 Bcfe of estimated proved reserves as of December 31, 2006. Approximately 81% of Questar E&P’s proved reserves, or 1,322.5 Bcfe, were located in the Rocky Mountain region of the United States, while the remaining 19%, or 308.9 Bcfe, were located in the Midcontinent region. Approximately 990.7 Bcfe of the proved reserves reported by Questar E&P at year-end 2006 were developed, while 640.7 Bcfe were proved undeveloped. The majority of the proved undeveloped reserves were

QUESTAR 2006 FORM 10-K 8

associated with the Company’s Pinedale Anticline leasehold. Natural gas comprised about 90% of Questar E&P’s total proved reserves at year-end 2006. See Item 2 of Part I and Note 17 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on Questar E&P’s proved reserves.

Questar E&P – Competition and Customers

Questar E&P faces competition in every part of its business, including the acquisition of reserves and leases. Its longer-term growth strategy depends, in part, on its ability to purchase reasonably priced reserves and develop them in a low-cost and efficient manner. Competition is particularly intense when prices are high, as has been the case in recent years.

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

Questar E&P – Regulation

Questar E&P 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.

Most Questar E&P leases in the Rocky Mountain area are granted by the federal government and administered by federal agencies. Development of Pinedale leasehold acreage is subject to the terms of certain winter-drilling restrictions. In 2004, Market Resources worked with federal and state officials in Wyoming to obtain authorization for limited winter-drilling activities and has developed innovative measures, such as drilling multiple wells from a single location, to minimize the impact of its activities on wildlife and wildlife habitat. A Supplemental Environmental Impact Statement is currently being prepared by the Bureau of Land Management, (BLM) to consider expanded winter-drilling and completion operations on the Pinedale Anticline. The presence of wildlife and potential endangered species could limit access to public lands. Various wildlife species inhabit Market Resources leaseholds at Pinedale and in other areas. Current federal regulations restrict activities during certain times of the year on portions of Market Resources leaseholds due to wildlife activity and/or habitat.

Wexpro

Wexpro develops and produces gas and oil on certain properties for affiliate Questar Gas under the terms of a comprehensive agreement, the Wexpro Agreement. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19-20% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation – its investment base. The term of the Wexpro Agreement coincides with the productive life of the gas and oil properties covered therein. Wexpro’s investment base totaled $260.6 million at December 31, 2006. See Note 14 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Wexpro Agreement.

Wexpro delivers natural gas production to Questar Gas at a price equal to Wexpro’s cost-of-service. Cost-of-service gas satisfied 43% of Questar Gas supply requirements during 2006 at prices that were significantly lower than Questar Gas cost for purchased gas.

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.

Wexpro owns oil-producing properties. Under terms of the Wexpro Agreement, revenues from crude-oil sales offset operating expenses and provide Wexpro with a return on its investment. Any remaining revenues, after recovery of expenses and Wexpro’s return on investment, are divided between Wexpro (46%) and Questar Gas (54%).

Wexpro 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

QUESTAR 2006 FORM 10-K 9

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.

See Item 2 of Part I and Note 17 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company’s cost-of-service proved reserves.

Gas Management

Gas Management provides natural gas-gathering and processing services to affiliates and third-party producers in the Rocky Mountain region. 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), a partnership that operates gas-gathering facilities in eastern Utah. Under a contract with Questar Gas, Gas Management also gathers cost-of-service volumes produced from properties operated by Wexpro.

Approximately 58% of Gas Management’s 2006 revenues were derived from fee-based gathering and processing agreements. The remaining revenues were derived from natural gas processing margins that are in part exposed to the frac spread. To reduce processing margin risk, Gas Management has restructured many of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. A keep-whole contract insulates producers from frac spread risk while a fee-based contract eliminates commodity price risk for the processing plant owner. To further reduce processing margin volatility associated with keep-whole contracts, Gas Management may also attempt to reduce processing margin risk with forward-sales contracts for NGL or hedge NGL prices and equivalent gas volumes with the intent to lock in a processing margin.

Energy Trading

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

Energy Trading uses derivatives to manage commodity price risk. Energy Trading primarily uses fixed-price swaps to secure a known price for a specific volume of production. Energy Trading does not engage in speculative hedging transactions. See Notes 1 and 9 to the consolidated financial statements included in Item 8 and in Item 7A of Part II of this Annual Report for additional information relating to hedging activities.

Questar Pipeline

Questar Pipeline is an interstate pipeline company that provides natural gas-transportation and underground storage services in Utah, Wyoming and Colorado. As a “natural gas company” under the Natural Gas Act of 1938, Questar Pipeline and certain subsidiary pipeline companies are regulated by the Federal Energy Regulatory Commission (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 2,503 miles of interstate pipeline with total daily capacity of 3,442 Mdth. Questar Pipeline’s core-transmission system is strategically located in the Rocky Mountain area near large reserves of natural gas in six major Rocky Mountain producing areas. Questar Pipeline transports natural gas from these producing areas to other major pipeline systems and to the Questar Gas distribution system. In addition to this core system, Questar Pipeline, through a subsidiary, owns and operates the 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.

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

QUESTAR 2006 FORM 10-K 10

Questar Pipeline – Customers, Growth and Competition

Questar Pipeline faces risk of recontracting firm capacity as contract terms expire. Questar Pipeline’s transportation system is nearly fully subscribed, and firm contracts had a weighted-average remaining life of 9.2 years as of December 31, 2006. All of Questar Pipeline storage capacity is fully contracted with a weighted-average remaining life of 7.5 years as of December 31, 2006.

Questar Gas remains Questar Pipeline’s largest transportation customer. During 2006, Questar Pipeline transported 116.7 MMdth for Questar Gas compared to 116.3 MMdth in 2005. Questar Gas has reserved firm-transportation capacity of 951 Mdth per day under long-term contracts, or about 50% of Questar Pipeline’s reserved capacity, during the three coldest months of the year. Questar Pipeline’s primary transportation agreement with Questar Gas will expire on June 30, 2017.

Questar Pipeline also transported 320.4 MMdth for nonaffiliated customers to pipelines owned by Kern River Pipeline, Northwest Pipeline, Colorado Interstate Gas, TransColorado, Wyoming Interstate Company and other systems. Questar Pipeline’s tariff does not contain an explicit hydrocarbon dewpoint limit for gas delivered into its system. Questar Pipeline is able to transport gas with a higher hydrocarbon dewpoint specification than most other systems through use of enhanced liquid handling and processing facilities on its system and agreements with third-party processors. As a consequence, Questar Pipeline must incur higher costs to meet the hydrocarbon dewpoint specifications of these downstream interconnecting pipelines. In effect, Questar Pipeline currently provides a bundled gas-transportation and dewpoint-management service for shippers at certain delivery points consistent with FERC’s policy statement on gas quality and interchangeability standards issued in June 2006. Questar Pipeline proposes to amend its tariff to enable it to manage hydrocarbon dewpoint levels on its system, in a fair and efficient manner, to meet downstream interconnecting pipeline gas quality specifications and maximize system throughput for its shipper.

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 Pipeline, are building gathering lines that allow producers to make direct connections to competing pipeline systems.

During 2006, Questar Pipeline completed a 27.2-mile expansion of its Overthrust Pipeline to connect with Kern River at Opal, Wyoming. The expansion went into service on January 1, 2007, and is supported with long-term contracts.

Questar Pipeline has two planned expansions during 2007. Overthrust Pipeline plans to extend 78 miles from Rock Springs to Wamsutter, Wyoming. This expansion will complete the western segment of the Rockies Express Pipeline project and is supported with a long-term capacity lease. Questar Pipeline plans to expand the capacity on its southern system with 58 miles of pipe looping its current system and additional compression. This project is supported with long-term contracts.

Southern Trails Pipeline

In mid-2002, Questar Southern Trails Pipeline, a Questar Pipeline subsidiary, placed the eastern segment of the Southern Trails pipeline into service. The eastern segment extends from the San Juan Basin to inside the California state line. Capacity on this segment is fully committed under contracts that expire in mid-2008 and mid-2015.

The California segment of the Southern Trails Pipeline, which extends from near the California-Arizona state line to Long Beach, California, is currently not in service. Questar Pipeline is pursuing several options to sell or place this line in service.

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

Questar Pipeline – Regulation

On January 18, 2007, the FERC proposed permanent standards of conduct regulation in a Notice of Proposed Rulemaking (NOPR) that will replace an Interim Rule governing the relationship between transmission providers and their energy affiliates. The Interim Rule was put forth January 9, 2007, by the FERC in response to Order No. 2004 being vacated November 17, 2006, by the U.S. Court of Appeals for the District of Columbia Circuit. The Court of Appeals found that the FERC had not adequately supported the application of the standards of conduct to a broader definition of energy affiliates in Order No. 2004. In its NOPR the FERC proposed that the standards of conduct apply only to marketing affiliates. The proposed definition of marketing affiliate is similar to the definition found in Order No. 497 (pre-Order No. 2004).

QUESTAR 2006 FORM 10-K 11

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.

Clay Basin Storage Gas

See Results of Operation included in Item 7 of Part II of this Annual Report for discussion of Clay Basin storage gas loss.

Questar Gas

Questar Gas distributes natural gas as a public utility in Utah, southwestern Wyoming and a small portion of southeastern Idaho. As of December 31, 2006, Questar Gas was serving 850,542 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 2006, Questar Gas added 26,095 customers, a 3.2% increase.

Questar Gas faces the same risks as other local-distribution companies. These risks include revenue variations based on seasonal changes in demand, sufficient gas supplies, declining residential usage per customer, adequate distribution facilities and adverse regulatory decisions. Questar Gas’s sales to residential and commercial customers are seasonal, with a substantial portion of such sales made during the heating season. The typical residential customer in Utah (defined as a customer using 115 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. The Company’s prior rate structure penalized the Company for declining usage per customer and rewarded the Company for increasing usage per customer. 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 will be limited to one percent of total revenues for the first year. The program will be reviewed after one year. Questar Gas recorded a $1.7 million revenue reduction in 2006 to recognize the impact of the CET.

In January 2007, the PSCU approved a demand-side management program (DSM) effective January 1, 2007. Under the DSM, Questar Gas will encourage the conservation of natural gas through advertising, rebates for efficient homes and appliances, and energy audits. The costs of the DSM will be deferred and recovered from customers through periodic rate adjustments.

Questar Gas minimizes gas supply risk with cost-of-service natural gas reserves. During 2006, Questar Gas satisfied 43% 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 17 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company’s cost-of-service proved reserves. Questar Gas also has a balanced and diversified portfolio of gas-supply contracts for volumes produced in Wyoming, Colorado, and Utah. Questar Gas has regulatory approval to include costs associated with hedging activities in its balancing account for pass-through treatment.

Questar Gas has designed its distribution system and annual gas-supply plan to handle design-day demand requirements. It periodically updates its design-day demand, the volume of gas that firm customers could use during extremely cold weather. For the 2006-07 heating season, Questar Gas used a design-day demand of 1.2 MMdth for firm customers.

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

QUESTAR 2006 FORM 10-K 12

Questar Gas – Regulation

As a public utility, Questar Gas is subject to the jurisdiction of the PSCU and PSCW. Natural gas sales and transportation services are made under rate schedules approved by the two regulatory commissions. Questar Gas is authorized to earn a return on equity of 11.2% in Utah and 11.83% in Wyoming. Both the PSCU and PSCW permit Questar Gas to recover gas costs through a balancing-account procedure and to reflect natural gas-price changes on a periodic, generally semi-annual basis. Questar Gas has also received permission from the PSCU and PCSW to reflect in its gas costs specified costs associated with hedging contracts.

See Note 11 of the consolidated financial statements included in Item 8 of Part II in this Annual Report for a discussion of gas-processing cost coverage.

Questar Gas has significant relationships with affiliates that have allowed it to lower its costs and improve efficiency. These affiliate relationships, however, are subject to oversight by regulatory commissions for evidence of subsidization and above-market payments.

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

Questar Gas – Competition

Questar Gas is a public utility and currently has no direct competition from other distributors of natural gas for residential and commercial customers. It has historically enjoyed a favorable price comparison with other energy sources used by residential and commercial customers except coal and occasionally fuel oil. It provides transportation service to industrial customers that can buy volumes of gas directly from others. Questar Gas earns lower margins on this transportation service than firm-sales service and could lose customers to Kern River.

Corporate and Other Operations

Questar’s Other Operations include commercial real-estate management; wellhead gas analysis and automation, field compression and engine maintenance.

Environmental Matters

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

Employees

At December 31, 2006, the Company had 2,188 employees, including 679 in Market Resources, 265 in Questar Pipeline, 1,175 in Questar Gas and 69 in Corporate and Other Operations.

Executive Officers

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

Primary Positions Held with the Company

and Affiliates, Other Business Experience

Name

Keith O. Rattie

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

Charles B. Stanley

Executive Vice President and Director, Questar (2002); President, Chief Executive Officer and Director, Market Resources and Market Resources subsidiaries (2002); Senior Vice President, Questar (2002 to 2002); Executive Vice President and Chief Operating Officer, Market Resources and Market Resources subsidiaries (2002 to 2002). Prior to joining Questar, Mr. Stanley was President, Chief Executive Officer and Director, Coastal Gas

QUESTAR 2006 FORM 10-K 13

International Co. (1995 to 2000); President and Chief Executive Officer, El Paso Oil and Gas Canada, Inc. (2000 to January 2002).

Alan K. Allred

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

R. Allan Bradley

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

Stephen E. Parks

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

Thomas C. Jepperson

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

Brent L. Adamson

Vice President Ethics, Compliance and Audit (2002); Director, Audit (1982 to 2002); Compliance Officer (1995 to 2002). Mr. Adamson announced his retirement effective March 1, 2007.

Abigail L. Jones

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

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.

The future price of natural gas, oil and NGL is unpredictable. Historically the price of natural gas, oil and NGL has been volatile and is likely to continue to be volatile in the future. Any significant or extended decline in commodity prices would impact the Company’s future financial condition, revenues, results of operations, cash flows and rate of growth. Because approximately 90% of Questar’s proved reserves at December 31, 2006, were natural gas, the Company is 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;

QUESTAR 2006 FORM 10-K 14

•

domestic and global economic conditions;

•

domestic political developments;

•

weather conditions;

•

domestic and foreign government regulations and taxes;

•

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

•

conservation efforts;

•

the price, availability and acceptance of alternative fuels;

•

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

•

differing Btu content of gas produced and quality of oil produced.

Questar uses derivative instruments to manage exposure to uncertain prices. Questar uses financial contracts to 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 otherwise experienced if commodity prices increase. 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 hedging arrangements with creditworthy counterparties (banks and industry participants) with a variety of credit requirements. Some contracts do not require the Company to post cash collateral, while others allow some amount of credit before requiring deposits of collateral for out-of-the-money hedges. The amount of credit available may vary depending on the credit ratings assigned to the Company’s debt securities. A substantial increase in the price of natural gas, oil and/or NGL could result in the requirement to deposit large amounts of collateral with counterparties that could seriously impact the Company’s cash liquidity. Additionally, a downgrade in the Company’s credit ratings to sub-investment grade could result in the acceleration of obligations to hedge counterparties.

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.

Questar faces many operating risks to develop and produce its reserves. 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;

QUESTAR 2006 FORM 10-K 15

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.

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 can not assure that insurance will be adequate to cover these losses or liabilities. Losses and liabilities arising from uninsured or underinsured events could have an adverse effect on the Company’s financial condition and operations.

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

A significant portion of Market Resources production, revenue and cash flow are derived from assets that are concentrated in a geographical area. While geographic concentration of assets provides scope and scale that can reduce operating costs and provide other operating synergies, asset concentration does increase exposure to certain risks. Market Resources has extensive operations on the Pinedale Anticline and in the Greater Green River Basin of southwestern Wyoming. 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.

Gas and oil operations involve numerous risks that might result in accidents and other operating risks and costs. There are inherent operating risks and hazards in the Company’s exploration and production, gas gathering, processing, transportation and distribution operations, such as fires, earthquakes, leaks, explosions and mechanical problems 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. In accordance with customary industry practice, the Company maintains insurance against some, but not all, of these risks and 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.

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

Questar must comply with numerous and complex regulations governing activities on federal and state lands in the Rocky Mountain region, notably the National Environmental Policy Act, the Endangered Species Act, 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 exploring for, finding and producing natural gas and oil on the Company’s Rockies leasehold. Certain environmental groups oppose drilling on some of Market Resources’ federal and state leases.

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

QUESTAR 2006 FORM 10-K 16

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. Finally, 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, oil and transportation operations on such lands.

Both Questar Pipeline and Questar Gas incur significant costs to comply with federal pipeline-safety regulations. Questar may also be affected by possible future regulations requiring the tracking, reporting and reduction of greenhouse-gas emissions pertaining to its operations.

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

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

Questar is dependent on bank credit facilities and continued access to capital markets to successfully execute its operating strategies. Questar also relies on access to short-term commercial paper markets. The Company is dependent on these capital sources to provide financing for certain projects. The availability and cost of these credit sources is cyclical, and these capital sources may not remain available or the Company may not be able to obtain money at a reasonable cost in the future. All 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. Management believes it is important to maintain investment grade credit ratings to conduct the Company’s businesses, but may not be able to keep investment grade ratings.

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.

Questar E&P and Cost-of-Service

Reserves – Questar E&P

The following table sets forth Questar E&P’s estimated proved reserves, the estimated future net revenues from the reserves and the standardized measure of discounted net cash flows as of December 31, 2006. The estimates were collectively prepared by Ryder Scott Company, H. J. Gruy and Associates, Inc. and Netherland, Sewell & Associates, Inc., independent reservoir-engineering consultants. Questar E&P does not have any long-term supply contracts with foreign governments or reserves of equity investees or of subsidiaries with a significant minority interest. At December 31, 2006, Questar E&P was the operator of approximately 82% of its estimated proved reserves. All reported reserves are located in the United States.

QUESTAR 2006 FORM 10-K 17


Estimated proved reserves
Natural gas (Bcf)	1,461.2
Oil and NGL (MMbbl)	28.4
Total proved reserves (Bcfe)	1,631.4
Proved developed reserves (Bcfe)	990.7
Estimated future net revenues before future
income taxes (in millions) (1)	$4,825.2
Standardized measure of discounted net cash
flows (in millions) (2)	$1,567.8

(1)

Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, using average year-end 2006 prices of $4.47 per Mcf for natural gas and $51.49 per bbl for oil and NGL combined, net of estimated production and development costs (but excluding the effects of general and administrative expenses; debt service; depreciation, depletion and amortization; and income tax expense).

(2)

The standardized measure of discounted future net cash flows prepared by the Company represents the present value of estimated future net revenues after income taxes, discounted at 10%.

Estimates of proved reserves and future net revenues are made at year-end, using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the remaining life of the properties (except to the extent a contract specifically provides for escalation). Year-end prices do not include the effect of hedging. Estimated quantities of proved reserves and future net revenues are affected by natural gas and oil prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating natural gas and oil reserves and their estimated values, including many factors beyond the control of the Company.

Questar E&P’s reserve statistics for the years ended December 31, 2004 through 2006, are summarized below:


Year	Year End Reserves (Bcfe)	Proved Gas and Oil Reserves Annual Production (Bcfe)	Reserve Life (Years)
2004	1,434.0	103.5	13.9
2005	1,480.4	114.2	13.0
2006	1,631.4	129.6	12.6

In 2006, gas and oil reserves increased 10%, after production and sales of producing properties, to 1,631.4 Bcfe versus a 3% increase in 2005 to 1,480.4 Bcfe. Questar E&P’s production replacement ratio was 217% in 2006 and 141% in 2005. Net reserve additions, revisions, purchases and sales in place totaled 280.7 Bcfe in 2006 and 160.6 Bcfe in 2005. Questar E&P’s five-year average finding cost of proved reserves per Mcfe was $1.53 in 2006, $1.08 in 2005 and $0.83 in 2004.

Finding costs measure the costs of finding, developing and acquiring new proved reserves. The production replacement ratio measures company success at replacing production during a specific period. If the production replacement ratio is greater than 100%, the Company added or replaced more reserves than it produced for the same period.

Questar E&P proved reserves by major operating areas at December 31, 2006 and 2005 follow:


	2006		2005
	(Bcfe)	(% of total)	(Bcfe)	(% of total)
Pinedale Anticline	931.9	57%	780.0	53%
Uinta Basin	248.3	15%	254.9	17%
Rockies Legacy	142.3	9%	144.4	10%
Rocky Mountains Total	1,322.5	81%	1,179.3	80%
Midcontinent	308.9	19%	301.1	20%
Questar E&P Total	1,631.4	100%	1,480.4	100%

QUESTAR 2006 FORM 10-K 18

Reserves – Cost-of-Service

The following table sets forth estimated cost-of-service proved natural gas reserves, which Wexpro develops and produces for Questar Gas under the terms of the Wexpro Agreement; and Wexpro proved oil reserves. The estimates of cost-of-service proved reserves were made by Wexpro reservoir engineers as of December 31, 2006. All reported reserves are located in the United States.


Estimated cost-of-service proved reserves
Natural gas (Bcf)	620.6
Oil (MMbbl)	4.4
Total proved reserves (Bcfe)	647.0
Proved developed reserves (Bcfe)	458.2

The gas reserves operated by Wexpro are delivered to Questar Gas at cost of service. Net income from oil properties remaining after recovery of expenses and Wexpro contractual return on investment under the settlement 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.

Reference should be made to Note 17 of the consolidated financial statements included in Item 8 of Part II of this Annual Report for additional information pertaining to both Questar E&P proved reserves and the Company’s cost-of-service reserves as of the end of each of the last three years.

In addition, to this filing, Questar E&P and Wexpro will each file estimated reserves as of December 31, 2006, with the Energy Information Administration in 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, 2006, 2005 and 2004. Lifting costs include labor, repairs, maintenance, materials, supplies and workovers, administrative costs of production offices, insurance and property and severance taxes.


	Year Ended December 31,
	2006	2005	2004
*Questar E&P* Volumes produced and sold Natural gas (Bcf) Oil and NGL (MMbbl)	113.9 2.6	100.0 2.4	89.8 2.3
Total production (Bcfe) Average realized price (including hedges) Natural gas (per Mcf) Oil and NGL (per bbl)	129.6 $ 6.00 49.12	114.2 $ 5.18 41.54	103.5 $ 4.18 30.97
Lifting costs (per Mcfe) Lease operating expense Production taxes	$ 0.57 0.45	$ 0.54 0.60	$ 0.50 0.46
Total lifting costs	$ 1.02	$ 1.14	$ 0.96

Cost-of-Service

Volumes produced

Natural gas (Bcf)

Oil and NGL (MMbbl)

38.8

0.4

40.0

0.4

38.8

0.4

QUESTAR 2006 FORM 10-K 19

Productive Wells

The following table summarizes Market Resources productive wells (including cost-of-service wells) as of December 31, 2006. All of these wells are located in the United States.


	Gas	Oil	Total
Gross	4,633	966	5,599
Net	2,065.6	456.2	2,521.8

Although many Market Resources 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 2006, there were 88 gross wells with multiple completions.

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

Leasehold Acres

The following table summarizes developed and undeveloped-leasehold acreage in which Market Resources owns a working interest as of December 31, 2006. “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 Market Resources interest is limited to royalty, overriding-royalty and other similar interests. All leasehold acres are located in the U.S.

Leasehold Acreage – December 31, 2006

Developed (1)

Undeveloped (2)

Total

Gross

Net

Gross

Net

Gross

Net

(in acres)


Arizona			480	450	480	450
Arkansas	32,049	10,310	3	1	32,052	10,311
California	25	2	1,293	192	1,318	194
Colorado	143,967	99,540	169,367	81,470	313,334	181,010
Idaho			44,175	10,643	44,175	10,643
Illinois	172	39	14,207	3,949	14,379	3,988
Indiana			1,890	702	1,890	702
Kansas	30,302	13,396	16,880	3,963	47,182	17,359
Kentucky			17,323	6,669	17,323	6,669
Louisiana	13,242	12,065	1,553	999	14,795	13,064
Michigan	89	8	6,240	1,262	6,329	1,270
Minnesota			313	104	313	104
Mississippi	2,904	1,798	965	398	3,869	2,196
Montana	19,829	8,374	299,847	51,507	319,676	59,881
Nevada	320	280	680	543	1,000	823
New Mexico	97,531	68,858	25,333	5,315	122,864	74,173
North Dakota	4,635	546	146,364	21,757	150,999	22,303
Ohio			202	43	202	43
Oklahoma	1,519,727	271,962	98,956	54,345	1,618,683	326,307
Oregon			43,869	7,671	43,869	7,671
South Dakota			204,398	107,829	204,398	107,829
Texas	147,467	61,167	70,761	53,977	218,228	115,144

QUESTAR 2006 FORM 10-K 20


Utah	128,173	104,340	288,313	148,611	416,486	252,951
Washington			26,631	10,149	26,631	10,149
West Virginia	969	115			969	115
Wyoming	260,030	161,295	345,692	227,857	605,722	389,152
Grand Total	2,401,431	814,095	1,825,735	800,406	4,227,166	1,614,501

(1)

Developed acreage is acreage spaced or assignable to productive wells.

(2)

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

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


Leaseholds Expiring	Acres Expiring
	Gross	Net
12 months ending December 31,	(in Acres)
2007	70,574	53,248
2008	80,408	49,310
2009	67,956	43,227
2010	36,599	17,008
2011 and later	175,963	159,381

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
	2006	2005	2004	2006	2005	2004
Net Wells Completed
Exploratory	0.9	6.1	4.7	5.2	1.5
Development	185.6	165.2	156.0	4.6	7.4	6.6

Gross Wells Completed
Exploratory	2	9	9	11	4
Development	408	370	322	18	15	13

Gas Management

Gas Management owns 1,474 miles of gathering lines in Utah, Wyoming, and Colorado. In conjunction with these gathering facilities, Gas Management owns compression facilities, field-dehydration and measuring systems. Gas Management is a 50% partner in Rendezvous, which owns an additional 229 miles of gathering lines and associated field equipment and is a 38% partner in Field Services which owns 65 miles of gathering lines and associated field equipment.

Gas Management owns processing plants that have an aggregate capacity of 440 MMcf of unprocessed natural gas per day.

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.

QUESTAR 2006 FORM 10-K 21

Questar Pipeline

Questar Pipeline has a maximum capacity of 3,442 Mdth per day and firm-capacity commitments of 2,152 Mdth per day. Questar Pipeline’s transmission system includes 2,503 miles of transmission lines that interconnect with other pipelines. Its core system includes two segments, often referred to as the northern system and southern system. The northern system extends from northwestern Colorado through southwestern Wyoming into northern Utah, while the southern system extends from western Colorado to Goshen, Utah. The transmission mileage includes lines at storage fields and tap lines used to serve Questar Gas, the 488 miles of the Southern Trails system in service that is owned by a subsidiary, and the 88 miles of Overthrust Pipeline that is owned by a subsidiary. The maximum-daily-capacity figures included above for Southern Trails is 85 Mdth and Overthrust is 1,119 Mdth. Questar Pipeline’s system ranges in size from lines that are less than four inches in diameter to the Overthrust line that is 36 inches in diameter. Southern Trails also owns 210 miles of pipeline comprising the California segment of the Southern Trails system, although this segment has not been placed in service. Questar Pipeline has major compression sites, including a complex near Rock Springs, Wyoming, that compress gas volumes from the transmission system for delivery to other pipelines, including systems that move gas volumes east.

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, and several smaller storage aquifers in northeastern Utah and western Wyoming. Through a subsidiary, Questar Pipeline owns processing plants near Price, Utah, and related gathering lines.

Questar Gas

Questar Gas distributes gas to customers in the major populated area of Utah, commonly referred to as the Wasatch Front, including the metropolitan Salt Lake area, Provo, Park City, Ogden, and Logan. It also serves customers throughout the state, including the cities of Price, Roosevelt, Vernal, Moab, Monticello, Fillmore, Cedar City and St. George. Questar Gas supplies natural gas to the southwestern Wyoming communities of Rock Springs, Green River, Evanston, Kemmerer and Diamondville and the southeastern Idaho community of Preston. To supply these communities Questar Gas owns and operates distribution systems and has a total of 25,527 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 Questar’s financial position. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. 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.

Pinedale Unit Net Profits Interest Litigation

In March 2006, Doyle Hartman and other alleged stakeholders (collectively the “Hartman Group”) filed a declaratory judgment action against Questar E&P, Wexpro and others in Sublette County District Court, Wyoming (Case No. 2006-6843) claiming a 5% net profits interest (NPI) in Pinedale leasehold interests. The Hartman Group seeks a declaratory judgment that the NPI burdens leases committed to the original Pinedale Unit regardless of whether the leases and lands have been eliminated from the Pinedale Unit by contraction and termination of that Unit. The defendants have denied the allegations and filed counterclaims for declaratory judgment and quiet title. In January 2007, the court dismissed a declaratory judgment action previously filed by Questar E&P and Wexpro in order to have all claims and counterclaims consolidated in a single case (Case No. 2006-6843). The court also granted the Hartman Group leave to amend its complaint which amended complaint alleges claims for declaratory judgment, accounting, damages for breach of contract, breach of royalty payment obligations, slander of title, breach of the duty of good faith and fair dealing, rescission, constructive trust and conversion. The Hartman Group has also filed motions for partial summary judgment which are pending with the court. The defendants will be filing a response to the amended complaint and motions for summary judgment.

Grynberg Cases

Questar affiliates are involved in various pending lawsuits filed by Jack Grynberg, an independent producer. 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.), Grynberg filed qui tam claims against Questar under the federal False Claims Act that were substantially similar to other cases filed against other industry pipelines and their affiliates. The cases were consolidated

QUESTAR 2006 FORM 10-K 22

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.

The defendants filed a motion contending that the court has no jurisdiction over the case because Grynberg cannot satisfy the statutory requirements for jurisdiction. The defendants argued that Grynberg’s allegations were publicly disclosed prior to the filing of his complaint and that Grynberg is not the “original source” of the information on which the allegations are based. By order dated October 20, 2006, the district court granted defendants motion and 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.

In Grynberg and L & R Exploration Venture v. Questar Pipeline Co., Civil No. 97CV0471 (D. Wyo.), Grynberg brought breach of contract claims, statutory claims and fraud claims against Questar entities related to a certain gas purchase contract for the purchase of gas produced from wells located in Wyoming. In December, 1998, the federal district court granted Questar’s motion for partial summary judgment on a contract termination issue and in June 2001, the court granted partial summary judgment dismissing the antitrust claims from the case. By order dated September 12, 2006, the judge also dismissed the fraud claims and ratable-take claims. The breach of contract claims are the only issues remaining to be decided. Grynberg has appealed the case to the U.S. Tenth Circuit Court of Appeals.

Kansas Cases

Energy Trading is a named defendant in cases pending in a Kansas state district court, Price v. Gas Pipelines, No. 99 C 30 (Dist. Ct. Kan.) and Price v. El Paso Entities, No. 03 C 23 (Dist. Ct. Kan.). These cases are similar to the cases filed by Grynberg, but the allegations of a conspiracy by the pipeline industry to set standards that result in the systematic undermeasurement of natural gas volumes and resulting underpayment of royalties are made on behalf of private lessors rather than on behalf of the federal government. The purported class involves all royalty owners of production from private land in Kansas, Wyoming and Colorado. Energy Trading opposes certification of the class and contends that it is not engaged in any gas measurement activities in Kansas. A hearing on plaintiffs’ motion to certify the class was held on April 1, 2005. The court has not issued a ruling in the case.

Environmental Claims

Questar Pipeline received a Notice of Violation from the Colorado Department of Public Health and Environment, Air Pollution Control Division (APCD) dated December 20, 2006, concerning its operation of the Powder Wash dew point plant and compressor station in Moffat County, Colorado. Specifically, APCD alleged that Questar Pipeline violated applicable air permitting regulations by failing to obtain the necessary permits and complying with best available control technology. Questar Pipeline has been working with the APCD to obtain these permits and resolve these allegations. This potential violation may result in civil penalties of an unknown and undetermined amount in excess of $100,000.

In 2004, the Environmental Protection Agency (EPA) issued two separate compliance orders alleging that Gas Management did not comply with regulatory requirements adopted to enforce the federal Clean Air Act. Both orders involved facilities in the Uinta Basin of eastern Utah that were purchased by Questar E&P in mid-2001. Gas Management believes it is operating the facilities and filing necessary reports in compliance with regulatory requirements; however, the EPA contends such facilities are located within Indian Country and are subject to additional Clean Air Act requirements not applicable to non-Indian Country lands administered by the state of Utah. As a consequence, EPA has broadened its allegations to include additional potential ongoing violations of the Clean Air Act for the referenced facilities. Other Gas Management facilities in the Uinta Basin have been added to the civil penalty discussions with the EPA, with similar allegations of Clean Air Act violations. These potential violations will likely result in civil penalties of an unknown and undetermined amount in excess of $100,000.

Regulatory Proceedings

See Note 11 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for information concerning various regulatory proceedings.

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

The Company did not submit any matters to a vote of stockholders during the last quarter of 2006.

QUESTAR 2006 FORM 10-K 23

PART II

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

5-Year Cumulative Total Return to Shareholders

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

[str10k4q2006005.gif]

The chart assumes $100 is invested at the close of trading on December 31, 2001, in the Company’s common stock, the indices of an industry peer group and the S&P 500 Composite Stock Price Index. It also assumes all dividends are reinvested. For 2006, the Company had a total return of 11.0% compared to 15.8% for the S&P 500 Index and 20.5% for the industry group. For the five-year period, the Company had a compound annual total of 29.7% compared to 6.2% for the S&P 500 Index and 22.2% for the industry group. The industry group is comprised of Energen Corporation, Equitable Resources, Inc., Kinder Morgan Inc., National Fuel Gas Company, Oneok Inc. and Southwestern Energy Company.

Information concerning the market for the common equity of the Company and the dividends paid on such stock is located in Note 16 to the consolidated financial statements included in Item 8 of Part II of this Annual Report. As of January 31, 2007, Questar had 9,432 shareholders of record.

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

The following table sets forth the Company’s purchases of common stock registered under Section 12 of the Exchange Act that occurred during the quarter ended December 31, 2006.

QUESTAR 2006 FORM 10-K 24

Total Number of Shares Purchased*

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 1, 2006 to

October 31, 2006

259

$81.41

November 1, 2006 to

November 30, 2006

10,937

86.25

December 1, 2006 to

December 31, 2006

3,485

86.98

Total

14,681

$86.34

*The numbers include shares purchased in conjunction with tax-payment elections under the Company’s Long-term Stock Incentive Plan. 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,
	2006	2005	2004	2003	2002
	(in millions, except per-share amounts)
Revenues	$2,835.6	$2,724.9	$1,901.4	$1,463.2	$1,200.7
Operating expenses
Cost of natural gas and other products sold	1,223.6	1,371.3	821.8	527.4	391.4
Operating and maintenance	286.8	262.8	213.6	205.0	179.8
General and administrative	135.0	123.1	114.2	94.3	108.8
Production and other taxes	108.7	120.2	90.9	70.7	44.2
Depreciation, depletion and amortization	308.4	250.3	216.2	192.4	185.0
Other expenses	42.0	35.4	29.1	33.6	17.3
Total operating expenses	2,104.5	2,163.1	1,485.8	1,123.4	926.5
Net gain (loss) on asset sales	25.3	4.7	0.3	(0.3)	23.9
Operating income	756.4	566.5	415.9	339.5	298.1
Interest and other income	9.3	9.0	6.3	8.0	33.2
Income from unconsolidated affiliates	7.5	7.5	5.1	5.0	11.8
Interest expense	(73.6)	(69.4)	(68.4)	(70.7)	(81.1)
Income taxes	(255.5)	(187.9)	(129.6)	(102.6)	(91.1)
Income before accounting changes	444.1	325.7	229.3	179.2	170.9
Cumulative effects of accounting changes				(5.6)	(15.3)
Net income	$ 444.1	$ 325.7	$ 229.3	$ 173.6	$ 155.6
Basic earnings per common share
Income before accounting changes	$5.20	$3.84	$2.74	$2.17	$2.09
Cumulative effect of accounting changes				(0.07)	(0.19)
Net income	$5.20	$3.84	$2.74	$2.10	$1.90
Diluted earnings per common share

QUESTAR 2006 FORM 10-K 25


Income before accounting changes	$5.07	$3.74	$2.67	$2.13	$2.07
Cumulative effect of accounting changes				(0.07)	(0.19)
Net income	$5.07	$3.74	$2.67	$2.06	$1.88
Weighted-average common shares outstanding
Used in basic calculation	85.5	84.8	83.8	82.7	81.8
Used in diluted calculation	87.6	87.1	85.7	84.2	82.6

Dividends per share	$0.93	$0.89	$0.85	$0.78	$0.725
Book value per common share at Dec. 31,	$25.67	$18.16	$17.05	$15.15	$13.88

Total assets at Dec. 31,	$5,064.7	$4,374.3	$3,684.9	$3,337.4	$3,090.1
Net cash provided from operating activities	966.2	695.1	585.7	436.6	466.6
Capital expenditures	916.1	712.7	446.5	325.6	364.6

Capitalization at Dec. 31,
Long-term debt, less current portion	$1,022.4	$ 983.2	$ 933.2	$ 950.2	$1,145.2
Common equity	2,205.5	1,549.8	1,439.6	1,261.3	1,138.7
Total capitalization	$3,227.9	$2,533.0	$2,372.8	$2,211.5	$2,283.9

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

SUMMARY

Questar reported net income of $444.1 million, or $5.07 diluted per share, in 2006 compared to $325.7 million, or $3.74 per diluted share, in 2005 and to $229.3 million, or $2.67 for 2004. Following is a comparison of net income by lines of business:


	Year Ended December 31,					Change		Change
	2006		2005	2004		2006 v. 2005		2005 v. 2004
	(in millions, except per-share amounts)
NET INCOME
Questar E&P	$253.9	$172.8			$108.2		$81.1		$64.6
Wexpro	50.0	43.7			35.3		6.3		8.4
Gas Management	42.6	35.7			21.0		6.9		14.7
Energy Trading and other	9.6	6.0			0.9		3.6		5.1
Market Resources total	356.1	258.2			165.4		97.9		92.8
Questar Pipeline	42.4	24.4			27.6		18.0		(3.2)
Questar Gas	37.0	36.0			31.5		1.0		4.5
Corporate and other operations	8.6	7.1			4.8		1.5		2.3
	$444.1	$325.7			$229.3		$118.4		$96.4

Earnings per share – diluted	$5.07	$3.74			$2.67		$1.33		$1.07

Market Resources net income increased 38% in 2006 compared to 2005 and 56% in 2005 over 2004. Primary factors for the higher income were increases in natural gas production, higher realized natural gas, oil and NGL prices, higher gas processing and gas gathering margins, and increases in the Wexpro investment base.

QUESTAR 2006 FORM 10-K 26

Questar Pipeline reported net income of $42.4 million in 2006 compared to $24.4 million in 2005 and $27.6 million in 2004. The increase in net income was the result of increased firm-transportation contracts supporting recent system expansions and higher NGL revenues. In 2005, Questar Pipeline recorded a $10.4 million after-tax asset impairment for the California segment of the company’s Southern Trails Pipeline. The 2004 results were lower by $3.0 million after tax as a result of an order to credit to transportation customers certain revenues from the sale of liquids recovered from gas processing.

Questar Gas net income increased 3% in 2006 versus 2005 and 14% in 2005 versus 2004. The 2006 results reflect continued customer growth and lower bad debt and depreciation expense. Higher 2005 revenues resulted from a record addition of 30,330 customers.

RESULTS OF OPERATION

Market Resources

Market Resources, which conducts natural gas and oil exploration, development and production, gas gathering and processing, wholesale gas and oil marketing and gas storage, reported $356.1 million of net income for 2006 compared with $258.2 million in 2005, a 38% increase, and $165.4 million in 2004. Operating income increased $160.8 million, or 38%, in the 2006 to 2005 comparison due primarily to increased natural gas production and higher realized prices at Questar E&P, an increased investment base at Wexpro, increased gas-processing plant margins at Gas Management and a net gain from asset sales. Following is a summary of Market Resources financial and operating results:


	Year Ended December 31,
	2006	2005	2004
	(in millions)
OPERATING INCOME
Revenues
Natural gas sales	$ 684.0	$ 517.6	$ 375.2
Oil and NGL sales	149.6	118.6	86.4
Cost-of-service gas operations	148.6	133.2	116.7
Energy marketing	668.7	902.8	506.6
Gas gathering, processing and other	184.9	156.0	100.4
Total revenues	1,835.8	1,828.2	1,185.3
Operating expenses
Energy purchases	652.6	888.3	499.7
Operating and maintenance	180.4	158.6	113.8
General and administrative	69.2	54.6	49.6
Production and other taxes	89.4	102.2	73.2
Depreciation, depletion and amortization	235.0	173.8	142.7
Exploration	34.4	11.5	9.2
Abandonment and impairment	7.6	7.9	15.8
Wexpro Agreement – oil-income sharing	5.5	6.1	4.7
Total operating expenses	1,274.1	1,403.0	908.7
Net gain from asset sales	25.2	0.9	0.3
Operating income	$ 586.9	$ 426.1	$ 276.9

OPERATING STATISTICS
Questar E&P production volumes
Natural gas (Bcf)	113.9	100.0	89.8
Oil and NGL (MMbbl)	2.6	2.4	2.3

QUESTAR 2006 FORM 10-K 27


Total production (Bcfe)	129.6	114.2	103.5
Average daily production (MMcfe)	355.2	312.9	282.8
Questar E&P average realized price, net to the well (including hedges)
Natural gas (per Mcf)	$6.00	$5.18	$4.18
Oil and NGL (per bbl)	$49.12	$41.54	$30.97
Wexpro investment base at December 31, net
of depreciation and deferred income taxes (millions)	$260.6	$206.3	$182.8
Natural gas processing volumes
NGL sales volumes (MMgal)	88.1	88.4	55.5
Processing fee based (in millions of MMBtu)	120.4	75.5	29.8
Natural gas processing revenues
NGL sales price (per gal)	$0.88	$0.77	$0.65
Processing fee based (per MMBtu)	$0.14	$0.15	$0.13
Natural gas gathering volumes (in millions of MMBtu)
For unaffiliated customers	153.9	145.0	128.7
For Questar Gas	42.2	43.1	39.0
For other affiliated customers	78.0	68.9	57.0
Total gathering	274.1	257.0	224.7
Gathering revenue (per MMBtu)	$0.29	$0.25	$0.22
Natural gas and oil marketing volumes (MMdthe)
For unaffiliated customers	118.3	118.5	91.2
For affiliated customers	102.0	91.8	82.5
Total marketing	220.3	210.3	173.7

Questar E&P

Questar E&P, a Market Resources subsidiary that conducts natural gas and oil exploration, development and production, reported net income of $253.9 million in 2006, up 47% from $172.8 million in 2005 and $108.2 million in 2003. The increase was driven by a combination of higher realized natural gas, oil and NGL prices and increased gas, oil and NGL production volumes.

Questar E&P reported production volumes increased to 129.6 Bcfe in 2006, a 13% increase compared to 2005. Natural gas is Questar E&P’s primary focus. On an energy equivalent basis, natural gas comprised approximately 88% of Questar E&P 2006 production. A comparison of natural gas-equivalent production by region is shown in the following table:


	Year Ended December 31,			Change	Change
	2006	2005	2004	2006 vs. 2005	2005 vs. 2004
	(in Bcfe)
Pinedale Anticline	39.5	33.2	23.5	6.3	9.7
Uinta Basin	25.1	25.6	24.8	(0.5)	0.8
Rockies Legacy	18.3	16.7	18.0	1.6	(1.3)
Rocky Mountain total	82.9	75.5	66.3	7.4	9.2
Midcontinent	46.7	38.7	37.2	8.0	1.5
Total Questar E&P	129.6	114.2	103.5	15.4	10.7

QUESTAR 2006 FORM 10-K 28

Questar E&P production from the Pinedale Anticline in western Wyoming grew 19% to 39.5 Bcfe in 2006 and comprised 30% of Questar E&P total production in the 2006 period compared to 33.2 Bcfe and 29% of 2005 production. Questar E&P completed 51 new wells during 2006 and 40 new wells at Pinedale during 2005.

In the Uinta Basin of eastern Utah, Questar E&P production decreased 2% to 25.1 Bcfe in 2006 compared to a year ago. Production increased 3% to 25.6 Bcfe in 2005 compared to 24.8 Bcfe in 2004 despite production constraints related to third quarter construction and maintenance on an interstate pipeline.

Production from Questar E&P Rocky Mountain “Legacy” properties increased 10% to 18.3 Bcfe in 2006 compared to a year ago. Excluding a one-time adjustment of 0.7 Bcfe, Legacy 2006 production was 17.6 Bcfe, an increase of 5% over the 2005 period driven by the company’s emerging gas play in the Vermillion Basin. Legacy assets include all Questar E&P Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin. Production during the 2005 period was negatively impacted by normal field decline, seasonal restrictions that limit access to leases and wells during the winter months, payout of a high-volume well that reduced the company’s working interest and mechanical problems that delayed completion of a new well in the Vermillion Basin.

In the Midcontinent, production grew 21% to 46.7 Bcfe in 2006, driven by ongoing infill-development drilling in the Elm Grove field in northwestern Louisiana.

Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. In 2006, the weighted average realized natural gas price for Questar E&P (including the impact of hedging) was $6.00 per Mcf compared to $5.18 per Mcf for the same period in 2005, a 16% increase. Realized oil and NGL prices in 2006 averaged $49.12 per bbl, compared with $41.54 per bbl during the prior year period, an 18% increase. A regional comparison of average realized prices including hedges is shown in the following table:


	Year Ended December 31,			Change	Change
	2006	2005	2004	2006 vs. 2005	2005 vs. 2004
Natural gas (per Mcf)
Rocky Mountains	$5.73	$5.01	$3.95	$0.72	$1.06
Midcontinent	6.47	5.49	4.57	0.98	0.92
Volume-weighted average	6.00	5.18	4.18	0.82	1.00
Oil and NGL (per bbl)
Rocky Mountains	$46.62	$42.08	$30.10	$4.54	$11.98
Midcontinent	54.93	40.25	32.98	14.68	7.27
Volume-weighted average	49.12	41.54	30.97	7.58	10.57

Approximately 70% in 2006 and 83% in 2005 of Questar E&P gas production was hedged or pre-sold. Hedging increased 2006 gas revenues by $53.7 million and reduced 2005 gas revenues by $173.9 million. Approximately 78% in 2006 and 70% in 2005 of Questar E&P oil production was hedged or pre-sold. Oil hedges reduced revenues $19.6 million in 2006 and $24.8 million in 2005.

Questar may hedge up to 100 percent of forecasted production from proved reserves to lock in acceptable returns on invested capital and to protect returns, cash flow and net income from a decline in commodity prices. During 2006, Questar E&P continued to take advantage of high natural gas and oil prices to hedge additional production through 2008. In 2006, the company began using basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials that may result from capacity constraints on regional gas pipelines. Derivative positions as of December 31, 2006, are summarized in Part II of Item 7A of this Annual Report.

Questar E&P production costs (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense, allocated-interest expense and production taxes) per Mcfe of production increased 6% to $2.99 per Mcfe in 2006 versus $2.83 per Mcfe in 2005 and $2.51 in 2004. Questar E&P production costs are summarized in the following table:

QUESTAR 2006 FORM 10-K 29


	Year Ended December 31,			Change	Change
	2006	2005	2004	2006 vs. 2005	2005 vs. 2004
	(per Mcfe)
Depreciation, depletion and amortization	$1.43	$1.18	$1.04	$0.25	$0.14
Lease operating expense	0.57	0.54	0.50	0.03	0.04
General and administrative expense	0.33	0.30	0.30	0.03
Allocated interest expense	0.21	0.21	0.21
Production taxes	0.45	0.60	0.46	(0.15)	0.14
Total production costs	$2.99	$2.83	$2.51	$0.16	$0.32

Depreciation, depletion and amortization expense rose due to higher costs for drilling, completion and related services, increased cost of steel casing, other tubulars and wellhead equipment, and the ongoing depletion of older, lower-cost reserves. Per unit lease operating expense increased due to increased costs of materials and consumables and higher well workover costs. General and administrative expenses increased due to higher labor costs and an increase in the allowance for doubtful accounts.

Production taxes per unit decreased with lower sales prices on natural gas, increased incentive tax credits related to well drilling and production enhancement projects, and adjustments to prior estimates. Most production taxes are based on a fixed percentage of commodity sales prices.

Questar E&P exploration expense increased $23.3 million in 2006 compared to 2005. The increase was primarily due to expenses for unsuccessful exploratory wells. Questar E&P plugged and abandoned the deep exploratory portion of the Stewart Point 15-29 well on the Pinedale Anticline after failing to establish commercial production in the Hilliard and Rock Springs formations. The company recorded a $10.0 million charge related to abandonment of the deep portion of the well, which was subsequently re-completed as a commercial well in the Lance Pool. Exploration expense increased $1.9 million in 2005 compared to 2004. The expense increase was due to increased exploratory seismic acquisition expenditures in the Midcontinent and Uinta Basin. Abandonment and impairment expense decreased $0.1 million in 2006 compared to 2005 and declined $5.3 million in 2005 compared to 2004. The 2004 amount included $2.3 million of expense due to a well with collapsed casing and $3.3 million for an abandoned coal bed methane project.

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. For income tax purposes, the company structured the sale of the Colorado properties and the 2006 acquisition of certain Louisiana properties to qualify as a reverse like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended.

Pinedale Anticline Drilling Activity

As of December 31, 2006, Market Resources (including both Questar E&P and Wexpro) operated and had working interest in 195 producing wells on the Pinedale Anticline compared to 144 and 104 at year-end 2005 and 2004, respectively. Of the 195 producing wells, Questar E&P has working interests in 173 wells, overriding royalty interests only in an additional 21 Wexpro-operated wells, and no interest in one well operated by Wexpro. Wexpro has working interests in 66 of the 195 producing wells.

In 2005, the Wyoming Oil and Gas Conservation Commission approved 10-acre-density drilling for Lance Pool wells on about 12,700 acres of Market Resources 18,208 acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the currently estimated productive limits of Market Resources core acreage in the field. With 10-acre-density drilling, the company currently believes that up to 932 wells will be required to fully develop the Lance Pool on its acreage.

Uinta Basin

During 2006, the company drilled or participated in 65 Wasatch and Upper Mesaverde gas wells, four horizontal and one vertical Green River Formation oil wells, and four deeper Blackhawk, Mancos and Dakota formations gas wells on its core acreage block.

As of December 31, 2006, Questar E&P had drilled five wells in the Flat Rock and Wolf Flat areas in the southern portion of the Uinta Basin, including two wells on its 12,577 gross acre Ute Tribe Exploration and Development Agreement lands and three wells on its State of Utah leasehold, and was drilling another well at year end.

QUESTAR 2006 FORM 10-K 30

Rockies Legacy

In the Vermillion Basin on the southwestern Wyoming-northwestern Colorado state line, Market Resources continues to evaluate the potential of several formations under the company’s 146,000 net leasehold acres. As of December 31, 2006, the company had recompleted two older wells, drilled and completed 13 new wells, and two were waiting on completion. The targets are the Baxter Shale, which extends across a 3,000-3,500 foot gross interval from about 9,500 feet deep to about 13,000 feet deep on most of the company’s leasehold in the basin, and the deeper Frontier and Dakota tight-sand formations at depths down to 14,000 feet.

Midcontinent

Questar E&P continued a two-rig infill-development project in the Elm Grove field in northwest Louisiana as it operated or participated in eight new wells that were completed in the fourth quarter of 2006. The company participated in the completion of 36 wells in Elm Grove field in 2006. In 2006, Questar E&P also acquired interests in 48 producing wells in nine spacing units in the Elm Grove field. The acquisition provides Questar E&P initial or additional working interest in approximately 75 undrilled locations.

Wexpro

Wexpro, a Market Resources subsidiary that develops and produces cost-of-service reserves for Questar Gas, reported net income of $50.0 million, in 2006 compared to $43.7 in 2005, a 14% increase and $35.3 million in 2004. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19% to 20% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation (investment base). Wexpro investment base at December 31, 2006, was $260.6 million, an increase of $54.3 million or 26%.

Gas Management

Gas Management, Market Resources gas-gathering and processing-services business, grew net income 19% to $42.6 million in 2006 from $35.7 million in 2005 and $21.0 million in 2004. Gas processing plant margin grew 72% from $24.3 million in 2005 to $41.7 million in 2006. Gathering volumes increased 17.1 million MMBtu to 274.1 million MMBtu in 2006 due primarily to expanding Pinedale production and new projects serving third parties in the Uinta Basin. Total gathering margins increased 9% despite increased start-up costs associated with the Pinedale liquids-gathering and transportation facilities.

To reduce processing margin risk, Gas Management has restructured a number of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. A keep-whole contract protects producers from frac spread risk while fee-based contracts eliminate commodity-price risk for the plant owner. In 2006, revenues from keep-whole contracts benefited from a 13% increase in realized NGL sales prices versus the prior-year period. Revenues from fee-based contracts were impacted by a 59% increase in processing volumes offset by a $0.01 decrease in the average rate charged per MMBtu processed compared with 2005. To further reduce margin volatility associated with keep-whole contracts, Gas Management began managing NGL price risk in 2004 by using forward-sales contracts. Forward sales contracts increased NGL revenues by $0.7 million in 2006 and decreased NGL revenues $1.0 million in 2005.

Income before income tax from Gas Management’s 50% interest in Rendezvous was $7.0 million for 2006 compared to $7.2 million in 2005 and $5.0 million in 2004. Rendezvous provides gas gathering services for the Pinedale and Jonah producing areas. Gas Management continues to invest in additional gas gathering and processing and liquids-handling facilities to serve growing equity and third-party production in its core areas of the Pinedale and Jonah fields in western Wyoming and the Uinta Basin in eastern Utah.

Gas Management completed its condensate and produced-water gathering and transportation facilities on Market Resources Pinedale Anticline leasehold in November 2005 in time to satisfy BLM conditions for expanded winter access.

Gas Management entered into an agreement with a third party producer to gather, compress and process gas in the Uinta Basin. Under terms of the fee-based agreement, the company constructed gas compression facilities and expanded its existing Red Wash gas plant to process an additional 70 MMcf per day of raw gas. The processed gas and liquids are redelivered to the producer. The new facilities were in service at the end of the third quarter 2005. Gas Management has formed a joint venture with the Ute Indian Tribe and another industry participant to build a gas gathering system for the Flat Rock area in southern Uinta Basin.

Energy Trading and Other

Energy Trading sells Market Resources equity gas and oil, provides risk-management services and operates a natural-gas storage facility, reported net income for 2006 of $9.6 million compared to $6.0 million in 2005 and $0.9 million in 2005. Service fee revenues from affiliates were $0.8 million higher in 2006 relative to 2005. Gross margins for gas and oil marketing (gross

QUESTAR 2006 FORM 10-K 31

revenues less costs for gas and oil purchases, transportation and gas storage), increased to $16.0 million for 2006 versus $14.5 million a year ago, a 10% increase. The increase in gross margin was due primarily to a 5% increase in volumes and increased storage activity over the same period last year.

Questar Pipeline

Questar Pipeline, which provides interstate natural gas-transportation and storage services, reported net income for 2006 of $42.4 million for 2006 compared with $24.4 million in 2005, a 74% increase, and $27.6 million in 2004. Operating income increased $31.6 million, or 53%, in the 2006 to 2005 comparison due primarily to increased transportation revenues and a 2005 impairment. The 2005 results were reduced by $10.4 million after tax for an impairment of the California segment of Southern Trails. Following is a summary of Questar Pipeline financial and operating results:


	Year Ended December 31,
	2006		2005			2004
	(in millions)
OPERATING INCOME
Revenues
Transportation	$ 119.9		$108.2	$105.5
Storage	37.6		37.4	37.7
Gas processing	6.3		5.6	7.3
NGL revenues	11.0		9.2	1.2
Other	6.6		5.6	4.8
Total revenues	181.4		166.0	156.5
Operating expenses
Operating and maintenance	33.1		30.7		26.3
General and administrative	19.3		25.2		29.4
Depreciation and amortization	31.5		29.4	28.2
Impairment of the California segment of Southern Trails Pipeline			16.0
Other taxes	6.6		5.8	6.6
Operating expenses	90.5		107.1	90.5
Net gain from assets sale			0.4
Operating income	$ 90.9		$ 59.3	$ 66.0

OPERATING STATISTICS
Natural gas-transportation volumes (MMdth)
For unaffiliated customers	320.4	259.3			220.5
For Questar Gas	116.7	116.3			116.5
For other affiliated customers	26.3	25.7			18.8
Total transportation	463.4	401.3			355.8
Transportation revenue (per dth)	$0.26	$0.27			$0.30
Firm daily transportation demand at December 31, (MMdth)	2.2	1.9			1.6

Revenues

Following is a summary of major changes in Questar Pipeline revenues for 2006 compared with 2005 and 2005 compared with 2004:

QUESTAR 2006 FORM 10-K 32


	Change in Revenues
	2005 to 2006	2004 to 2005
	(in millions)
Transportation
New transportation contracts	$14.4	$ 4.7
Expiration of transportation contracts	(2.7)	(2.0)
Storage	0.2	(0.3)
Gas processing	0.7	(1.7)
NGL revenues
Change in NGL prices and volumes	4.2	5.6
Adjustment to credit of NGL revenues in 2005	(2.4)	2.4
Other	1.0	0.8
Increase	$15.4	$ 9.5

As of December 31, 2006, Questar Pipeline had firm-transportation contracts of 2,152 Mdth per day compared with 1,920 Mdth per day as of December 31, 2005, and 1,643 Mdth per day as of December 31, 2004. Questar Pipeline has expanded its transportation system in response to growing regional natural gas production and transportation demand. In the second quarter of 2005, Questar Pipeline began operating a lateral to an electric generation power plant with a capacity of 190 Mdth per day. In the fourth quarter of 2005, Questar Pipeline completed an expansion of its southern system, which added capacity of 102 Mdth per day. On January 1, 2006, Questar Pipeline subsidiary, Questar Overthrust Pipeline, placed in service an interconnection with Kern River Gas Transmission Company that added capacity of 220 Mdth per day. Each of these expansion projects was fully subscribed with long-term contracts.

Questar Gas is Questar Pipeline’s largest transportation customer with contracts for 951 Mdth per day, including 50 Mdth per day for winter-peaking service. The majority of Questar Gas transportation contracts extend through mid 2017.

Questar Pipeline primary storage facility is Clay Basin 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 one to 12 years and 100% of the firm-storage capacity at the aquifer facilities for terms extending for 11 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 revenues increased 20% in 2006 over 2005 due to 21% higher prices and 33% higher volumes offset by a 2005 $2.4 million adjustment due to a resolution of a liquid sharing arrangement in a fuel-gas reimbursement proceeding. The 2005 NGL revenues were $5.6 million higher than 2004 due to higher prices and volumes and $2.4 million because of the adjustment.

During the third quarter of 2005, Questar Pipeline received approval of a settlement with customers that resolved outstanding issues in the 2004 and 2005 fuel gas reimbursement percentage (FGRP) filings. Included in this settlement was a resolution of the amount of liquid revenues at the Kastler plant to be retained by Questar Pipeline. Questar Pipeline recorded the impact of the settlement in third quarter 2005 increasing liquid revenues by $2.4 million and net income by $1.5 million. See Note 11 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of Questar Pipeline’s FGRP proceedings.

Expenses

Operating, maintenance, general and administrative expenses decreased by 6% to $52.4 million in 2006 compared to $55.9 million in 2005 and $55.7 million in 2004. Beginning in July 2005 customers at the company’s carbon dioxide processing plant

QUESTAR 2006 FORM 10-K 33

began supplying their own fuel gas, which accounted for $1.0 million of the decrease. Operating, maintenance, general and administrative expenses per dth transported were $0.11 in 2006 compared with $0.14 in 2005 and $0.16 in 2004. Operating, maintenance, general and administrative expenses include processing and storage costs.

Depreciation expense increased 7% in 2006 compared to 2005 and 4% in 2005 compared to 2004 due to investment in pipeline expansions.

Clay Basin Storage

Questar Pipeline conducts periodic pressure tests on its Clay Basin storage facility. Beginning with a test in April 2002, the company noted a discrepancy between the book volumes of cushion gas at Clay Basin and the volumes implied by pressure data. Questar Pipeline retained a reservoir consultant to model the reservoir and determine the size and cause of the discrepancy. The company conducted six additional pressure tests from April 2004 to October 2006 to validate the model.

The reservoir model indicates from 0 to 3.8 Bcf of gas may be missing from Clay Basin, with the most likely amount of 3.2 Bcf. The cumulative gas loss is due to imprecision inherent in measurement of large injection and withdrawal volumes as well as reservoir heterogeneity that impacts storage reservoir performance. The cushion gas loss represents 0.25% of the volume of gas cycled in and out of the reservoir over the past 30 years. There is no indication that the reservoir is leaking. The Clay Basin reservoir is functioning as expected to meet customer requirements.

Questar Pipeline is discussing with its firm-storage customers the recording of the loss of gas as a reduction of native gas remaining in the reservoir and various tariff changes. This accounting treatment would not impact Questar Pipeline net income. Alternatively, the FERC may require Questar Pipeline to adjust recoverable cushion gas, and reduce earnings by about $3 million after tax.

Southern Trails Pipeline

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

Questar Gas

Questar Gas, which provides natural gas distribution services in Utah, Wyoming and Idaho, reported net income of $37.0 million for 2006 compared with $36.0 million in 2005, a 3% increase, and $31.5 million in 2004. Operating income increased $2.4 million, or 3%, in the 2006 to 2005 comparison due primarily to higher margins from customer growth and lower bad debt and depreciation expenses. Following is a summary of Questar Gas’s financial and operating results:


	Year Ended December 31,
	2006	2005	2004
	(in millions)
OPERATING INCOME
Revenues
Residential and commercial sales	$ 988.4	$867.8		$680.7
Industrial sales	23.5	40.1		49.1
Transportation for industrial customers	6.7	5.9		6.4
Service	7.1	6.6		5.3
Other	38.9	42.1		22.7
Total revenues	1,064.6	962.5		764.2
Cost of natural gas sold	821.8	720.2		536.1
Margin	242.8	242.3		228.1
Operating expenses
Operating and maintenance	73.2	73.7		69.2
General and administrative	41.9	39.3		35.6
Rate-refund obligation				4.1

QUESTAR 2006 FORM 10-K 34


Depreciation and amortization	40.9	45.8	42.0
Other taxes	11.6	11.0	9.8
Total operating expenses	167.6	169.8	160.7
Net loss from asset sales	(0.3)		(0.2)
Operating income	$ 74.9	$ 72.5	$ 67.2

OPERATING STATISTICS
Natural gas volumes (MMdth)
Residential and commercial sales	102.2	96.3	93.0
Industrial sales	3.1	5.7	8.8
Transportation for industrial customers	35.5	31.2	34.3
Total industrial	38.6	36.9	43.1
Total deliveries	140.8	133.2	136.1

Natural gas revenue (per dth)
Residential and commercial	$9.67	$9.01	$7.32
Industrial sales	7.64	7.06	5.56
Transportation for industrial customers	0.19	0.19	0.19
System natural gas cost (per dth)	$ 6.54	$6.46	$5.20
Temperatures – colder (warmer) than normal	(2%)	(3%)	3%
Temperature-adjusted usage per customer (dth)	113.6	113.3	114.9
Customers at December 31, (in thousands)	850.5	824.4	794.1

Margin Analysis

Questar Gas’s margin (revenues less gas costs) increased $0.5 million in 2006 compared to 2005, and $14.2 million in 2005 compared with 2004. Following is a summary of major changes in Questar Gas’s margin for 2006 compared to 2005 and 2005 compared to 2004:


	Change in Margin
	2005 to 2006	2004 to 2005
	(in millions)
New customers	$ 6.9	$ 6.6
Conservation enabling tariff	(1.7)
Change in usage per customer	0.5	(1.6)
Interest on past-due receivables	0.6	1.2
Change in rates	(4.9)
Gas-processing revenues collected from customers	0.7	0.9
Recovery of gas-cost portion of bad-debt costs	(2.8)	2.1
Other, including shifting between rate classes	1.2	5.0
Increase	$ 0.5	$14.2

Temperature-adjusted usage per customer increased less than 1% in 2006 compared to 2005 and decreased 1% in 2005 compared to 2004. The impact on the company’s margin from changes in usage per customer has been mitigated by a conservation enabling tariff that was approved by the PSCU in October 2006, effective back to the beginning of 2006. Questar Gas recorded a reduction in margin of $1.7 million in 2006 to reflect the impact of changes in usage per customer. See Note 11 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of the conservation enabling tariff.

QUESTAR 2006 FORM 10-K 35

Effective June 1, 2006, Utah customer rates were reduced by $9.7 million per year, primarily to reflect changes in the company’s depreciation rates. Questar Gas realized $4.9 million in reduced revenues from this rate change during the last seven months of 2006. Depreciation expense was approximately $5.3 million lower for this seven-month period as a result of the depreciation rate change. See Note 11 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of the rate changes.

Weather, as measured in degree days, was 2% and 3% warmer than normal in 2006 and 2005, respectively compared with 3% colder than normal in 2004. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations. At December 31, 2006, Questar Gas was serving 850,542 customers, up from 824,447 at December 31, 2005.

Industrial deliveries (including sales and transportation) increased 5% in 2006 compared to 2005. Industrial deliveries declined 14% in 2005 compared with 2004 primarily driven by lower power-generation requirements and customers changing to the residential and commercial rate schedules.

Expenses

Cost of natural gas sold increased 14% in 2006 compared to 2005 due primarily to higher gas purchase expenses per dth and a 3% increase in volumes sold. Cost of natural gas sold increased 34% in 2005 compared with 2004. 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, 2006, Questar Gas had a $34.3 million over-collection balance in the purchased-gas adjustment account representing costs recovered from customers in excess of costs incurred. In November 2005, rates were increased significantly to recover increased gas costs caused by the Gulf Coast hurricanes. Questar Gas reduced rates in Utah and Wyoming effective November 1, 2006, by more than the prior year increases.

Operating, maintenance, general and administrative expenses increased 2% in 2006 compared to 2005 due primarily to higher labor costs offset by lower bad debt costs. These expenses increased 8% in 2005 compared to 2004 due to higher labor costs and bad debt costs. Operating, maintenance, general and administrative expenses per customer were $135 in 2006 compared to $137 in 2005 and $132 in 2004.

Depreciation expense decreased 11% in 2006 compared to 2005 primarily as a result of reduced depreciation rates effective June 1, 2006, in accordance with a PSCU order as discussed above. This offsets the depreciation impact of plant additions from customer growth, which caused depreciation expense to increase 9% in 2005 compared with 2004.

Rate Matters

See Note 11 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for a discussion of the Conservation Enabling Tariff, a rate reduction in Utah and recovery of gas processing costs. Questar Gas is subject to the requirements of the Pipeline Safety Improvement Act. Questar Gas estimates that it will cost $4.0 to $5.0 million per year to comply with the act, not including costs of pipeline replacement if necessary. The PSCU has allowed Questar Gas to recover $2.0 million per year of these costs beginning June 2006 and to record a regulatory asset for additional incremental operating costs incurred to comply with this Act.

Corporate and Other Operations

Corporate and Other Operations includes sales to affiliates and from gas measurement activities.


	Year Ended December 31,
	2006	2005	2004
	(in millions)
OPERATING INCOME
Revenues	$17.0	$ 19.1		$35.6
Operating expenses
Cost of products sold	4.8	5.4		5.9
Operating and maintenance	1.2	0.8		11.0

QUESTAR 2006 FORM 10-K 36


General and administrative	5.6	5.2	8.5
Depreciation and amortization	1.1	1.3	3.3
Other taxes	1.0	1.2	1.3
Total operating expenses	13.7	13.9	30.0
Net gain from asset sales	0.4	3.4	0.2
Operating income	$ 3.7	$ 8.6	$ 5.8

Revenues and total operating expenses decreased in 2005 compared with 2004 due to the 2004 reorganization of information-technology-related businesses and the May 2005 sale of data-hosting assets.

Consolidated Operating Results After Operating Income

Interest and Other Income

The details of interest and other income for 2006, 2005 and 2004 are shown in the table below:


	Year Ended December 31,
	2006	2005	2004
	(in millions)
Interest income and other earnings	$ 6.0	$3.3	$1.9
Allowance for other funds used during
construction (capitalized finance costs)	1.0	0.7	0.3
Return earned on working-gas inventory
and purchased-gas-adjustment account	5.9	5.0	4.1
Total	$12.9	$9.0	$6.3

Net gain on asset sales

During 2006, Questar E&P sold certain proved reserves and undeveloped leasehold interests in western Colorado and recognized a pre-tax gain of $22.7 million. The gain is included in the Consolidated Statement of Income line item “Net gain on asset sales”. For income tax purposes, the Company structured the sale of the Colorado properties and the March 2006 acquisition of certain Louisiana properties to qualify as a reverse like-kind exchange of property under Section 1031 of the Internal Revenue Code of 1986, as amended.

Income from unconsolidated affiliates

Gas Management has a 50% interest in Rendezvous that provides gas-gathering services for the Pinedale and Jonah producing areas of western Wyoming. Gas Management’s share of Rendezvous earnings amounted to $7.0 million in 2006 compared to $7.2 million in 2005 and $5.0 million in 2004. Rendezvous gathering volumes increased 1% in 2006 compared to 2005 and 47% in 2005 compared to 2004.

Interest expense and loss on early extinguishment of debt

Interest expense rose in 2006 compared to 2005 due primarily to increased average debt levels during and higher interest rates on short-term debt outstanding in the early part of 2006. Interest expense rose in 2005 because the Company increased borrowings to meet hedging collateral calls precipitated by increases in natural gas and oil prices. Market Resources recognized a $1.7 million pre-tax loss in 2006 on the early extinguishment of its 7% Notes due 2007.

Net mark-to-market loss on basis 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 mark-to-market losses of $1.9 million on the NYMEX/Rockies basis swaps in 2006.

Income taxes

The effective combined federal and state income tax rate was 36.5% in 2006, 36.6% in 2005 and 36.1% in 2004.

QUESTAR 2006 FORM 10-K 37

LIQUIDITY AND CAPITAL RESOURCES

Operating Activities

Net cash provided from operating activities increased 39% in 2006 compare to 2005 and 19% in 2005 compared to 2004 due primarily to higher net income, changes in operating assets and liabilities and noncash adjustments to income.


	Year Ended December 31,						Change		Change
	2006			2005	2004		2006 vs. 2005		2005 vs. 2004
	(in millions)
Net income		$444.1	$325.7			$229.3		$118.4		$ 96.4
Noncash adjustments to net income		438.3	378.7			359.8		59.6		18.9
Changes in operating assets and liabilities		83.8	(9.3)			(3.4)		93.1		(5.9)
Net cash provided from operating activities		$966.2	$695.1			$585.7		$271.1		$109.4

Investing Activities

Capital spending in 2006 amounted $916.1 million. The details of capital expenditures in 2006 and 2005 and a forecast for 2007 are shown in the table below:


	Year Ended December 31,
	2007 Forecast	2006	2005
	(in millions)
*Market Resources*
Drilling and other exploration	$ 31.4	$ 13.6	$ 51.7
Dry exploratory well expenses		26.3	3.1
Development drilling	476.8	532.6	355.1
Wexpro development drilling	62.6	76.8	53.7
Reserve acquisitions	1.0	29.3	3.5
Production	14.2	22.7	24.8
Gathering and processing	108.5	80.4	96.7
Storage	0.2	1.1	0.5
General	5.1	5.6	2.9
Capital expenditure accruals		(35.7)	(15.8)
	699.8	752.7	576.2
*Questar Pipeline*
Transmission system	115.7	13.5	60.2
Overthrust Pipeline	197.3	58.3
Southern Trails Pipeline	1.5	0.1	0.7
Storage	16.9	2.5	3.4
Gathering and processing	3.0	3.4	0.1
General	5.5	2.0	1.1
Capital expenditure accruals		(3.7)	1.9
	339.9	76.1	67.4
*Questar Gas*
Distribution system and customer additions	99.0	84.5	46.9
General	17.4	12.7	17.0
Capital expenditure accruals		(10.5)	4.0

QUESTAR 2006 FORM 10-K 38


	116.4	86.7	67.9
Corporate and Other Operations	1.1	0.6	1.2
Total capital expenditures	$1,157.2	$916.1	$712.7

Market Resources

In 2006 and 2005, Market Resources increased drilling activity at Pinedale and in the Midcontinent region. A water and condensate gathering system to serve the Pinedale Anticline was constructed in 2005. During 2006, Market Resources participated in 570 wells (196.3 net), resulting in 186.5 net successful gas and oil wells and 9.8 net dry or abandoned wells. The 2006 net drilling-success rate was 95%. There were 131 gross wells in progress at year end. Market Resources also increased investment in its midstream gathering and processing-services business to expand capacity in both western Wyoming and eastern Utah in response to growing equity and third-party production volumes.

Questar Pipeline

During 2006, a Questar Pipeline subsidiary completed a 27.2 miles extension of the Overthrust Pipeline from the Uinta County, Wyoming to a connection with the Kern River Gas Transmission pipeline at Opal, Wyoming.

Questar Gas

During 2006, Questar Gas added 818 miles of main, feeder and service lines to provide service to 26,095 new customers.

Financing Activities

Net cash provided from operating activities was sufficient to fund net capital expenditures and pay $79.7 million of dividends. On May 11, 2006, Market Resources sold $250 million principal amount of 6.05% Notes due 2016. Net proceeds of $247 million were used for general corporate purposes including the June 14, 2006, early extinguishment of its $200 million of 7% Notes due 2007 and repayment of short-term debt. Market Resources recorded a $1.7 million charge related to the early extinguishment of the 7% Notes. In 2005, Questar Gas borrowed $50 million from a bank under a five-year loan agreement and used the proceeds to repay short-term debt.

Short-term debt amounted to $40.0 million at December 31, 2006, and was comprised of commercial paper with an average interest rate of 5.4%. A year earlier short-term debt amounted to $94.5 million and was comprised of commercial paper with an average interest rate of 4.43%. Questar’s commercial paper borrowings are backed by short-term line-of-credit arrangements. At December 31, 2006, the Company had $400 million of short-term lines of credit available and Market Resources had a $182 million long-term revolving-credit facility with banks.

Questar consolidated capital structure consisted of 33% combined short- and long-term debt and 67% common shareholders’ equity at December 31, 2006, compared to 41% combined short- and long-term debt and 59% common shareholders’ equity a year earlier. Ratings of senior-unsecured debt as of December 31, 2006, were as shown below. Standard & Poor’s and Moody’s ratings were designated as stable.


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

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, Questar enters into a variety of contractual cash obligations and other commitments. The following table summarizes the significant contractual cash obligations as of December 31, 2006:

QUESTAR 2006 FORM 10-K 39


	Payments Due by Year
	Total	2007	2008-2009	2010-2011	After 2011
	(in millions)
Long-term debt	$1,033.5	$10.0	$101.4	$242.0	$680.1
Gas-purchase contracts	291.5	169.8	95.5	26.2
Transportation contracts	103.4	12.9	25.2	24.8	40.5
Operating leases	30.1	5.6	11.4	10.3	2.8
Total	$1,458.5	$198.3	$233.5	$303.3	$723.4

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 decisions 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 remedial costs. The subjective decisions and variances in data for various fields make these estimates less precise than other estimates included in the financial statement disclosures. For 2006, revisions of reserve estimates, other than revisions related to Pinedale increased-density, resulted in a 23.8 Bcfe decrease in Questar E&P’s proved reserves and a 21.5 Bcfe increase in cost-of-service proved reserves, representing approximately one percent and three percent of reported proved reserves, respectively, as of December 31, 2006. Revisions associated with Pinedale increased-density drilling added 170.4 Bcfe to Questar E&P’s estimated proved reserves at December 31, 2006, and 104.6 Bcfe of additional cost-of-service proved reserves. See Note 17 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.

QUESTAR 2006 FORM 10-K 40

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

Accounting for Derivatives Contracts

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

Revenue Recognition

Revenues are recognized in the period that services are provided or products are delivered. Questar E&P uses the sales method of accounting whereby revenue is recognized for all gas, oil and NGL sold to purchasers. Revenues include estimates for the two most recent months using published commodity index prices 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 nongas 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 will be limited to one percent of total revenues for the first year.

Rate Regulation

Regulatory agencies establish rates for the storage, transportation, distribution and sale of natural gas. The regulatory agencies also regulate, among other things, the extension and enlargement or abandonment of jurisdictional natural gas facilities. Regulation is intended to permit the recovery, through rates, of the cost of service, including a return on investment. Questar Gas and Questar Pipeline follow SFAS 71, “Accounting for the Effects of Certain Types of Regulation,” that requires the recording of regulatory assets and liabilities by companies subject to cost-based regulation. The FERC, PSCU and PSCW have accepted the recording of regulatory assets and liabilities.

Employee Benefit Plans

The Company has pension and postretirement-benefit plans covering a majority of its employees. The calculation of the Company’s expense and liability associated with its benefit plans requires the use of a number 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 makes assumptions based on market indicators and advice from consultants. The Company believes that the liability discount rate and the expected long-term rate of return on benefit plan assets are critical assumptions.

QUESTAR 2006 FORM 10-K 41

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 5.75% as of December 31, 2006, and 6.00% as of December 31, 2005. A 0.25% decrease in the discount rate increased the Company’s 2006 qualified pension annual expense by $1.5 million.

In September 2006, the FASB issued SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” The new accounting standard required disclosure of the over or under funded status of defined-benefit plans on the balance sheet effective with annual reports on Form 10-K for the year ending December 31, 2006. The over or under funded defined-benefit pension position was measured by the difference in the fair value of plan assets and the projected benefit obligation. The projected benefit obligation includes an estimate of future salary changes. The over or under funded position of other postretirement benefits was measured by the difference in the fair value of plan assets and the accumulated benefit obligation.

The expected long-term rate of return on benefit plan assets reflects the average rate of earnings expected on funds invested or to be invested to provide for the benefits included in the benefit plan liability. The Company establishes the expected long-term rate of return at the beginning of each fiscal year giving consideration to the benefit plan’s investment mix and the historical and forecasted rates of return on these types of securities. The expected long-term rate of return determined by the Company was 8.00% as of January 1, 2006 and 8.25% as of January 1, 2005. Benefit plan expense typically increases as the expected long-term rate of return on plan assets decreases. A 0.25% decrease in the expected long-term rate of return causes a $0.7 million increase in 2006 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 exposures arise from commodity-price changes for natural gas, oil and NGL, and volatility in interest rates. Energy Trading has long-term contracts for pipeline capacity and is obligated for transportation services with no guarantee that it will be able to recover the full cost of these transportation commitments.

Commodity-Price Risk Management

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

Market Resources has established policies and procedures for managing commodity-price risks through the use of derivatives. Natural gas- and oil-price hedging support Market Resources rate of return and cash flow targets and protects earnings from downward movements in commodity prices. The volume of hedged production and the mix of derivative instruments are regularly evaluated and adjusted by management in response to changing market conditions and reviewed periodically by the Finance and Audit Committee of the Company’s Board of Directors. 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 and does not hedge undeveloped reserves or Questar E&P equity NGL.

Market Resources uses fixed-price swaps to manage natural gas, oil and NGL price risk. 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. 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. To reduce exposure to highly volatile daily and monthly commodity prices, the Company uses a derivative instrument that exchanges or “swaps” the “floating” or daily price of the commodity for a fixed-price for the specified period (typically for periods of three months or longer). The Company enters into these transactions with banks and industry counterparties with investment-grade credit ratings. Swap agreements do not require the physical transfer of gas between the parties at settlement. Swap transactions are settled monthly, in cash, with one party paying the other for the net difference in prices, multiplied by the relevant volume, for the settlement period.

QUESTAR 2006 FORM 10-K 42

Generally derivative instruments are matched to equity gas and oil production, thus qualifying as cash flow hedges under the accounting provisions of SFAS 133 as amended and interpreted. Changes in the fair value of cash-flow hedges are recorded on the balance sheet and in other comprehensive income or 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 also entered into natural gas basis-only swaps in 2006 to manage the risk of a widening of basis differentials in the Rocky Mountains. These contracts are marked-to-market with any change in the valuation recognized in the determination of net income.

Market Resources enters into commodity price derivative arrangements with several banks and energy-trading firms with a variety of credit requirements. Some contracts do not require collateral deposits, while others allow some amount of credit before Market Resources is required to deposit collateral for out-of-the-money contracts. The amount of credit available may vary depending on the credit rating assigned to Market Resources debt. In addition, to the counterparty arrangements, Market Resources has a $182 million long-term revolving-credit facility with banks with no borrowings outstanding at December 31, 2006.

A summary of Market Resources derivative positions for equity production as of December 31, 2006, is shown below. Currently fixed-price and basis-only swaps are with creditworthy counterparties. Fixed-price swaps allow Market Resources to realize a known price for a specific volume of production delivered into a regional sales point. The fixed-price swap price is then reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price.


	Rocky			Rocky
Time Periods	Mountains	Midcontinent	Total	Mountains	Midcontinent	Total
				Estimated
	Gas (in Bcf) Fixed-Price Swaps			Average price per Mcf, net to the well
2007
First half	23.1	15.4	38.5	$6.88	$7.81	$7.25
Second half	23.5	15.6	39.1	6.88	7.81	7.25
12 months	46.6	31.0	77.6	6.88	7.81	7.25

2008
First half	16.9	12.2	29.1	$7.19	$7.98	$7.52
Second half	17.9	12.3	30.2	7.16	7.98	7.49
12 months	34.8	24.5	59.3	7.18	7.98	7.51

2009
First half	13.4	8.7	22.1	$7.07	$7.55	$7.26
Second half	13.7	8.8	22.5	7.07	7.55	7.26
12 months	27.1	17.5	44.6	7.07	7.55	7.26

	Gas (in Bcf) Basis-Only Swaps			Estimated Average basis per Mcf vs. NYMEX
2007
First half	8.4		8.4	$1.92		$1.92
Second half	8.6		8.6	1.92		1.92
12 months	17.0		17.0	1.92		1.92

QUESTAR 2006 FORM 10-K 43


2008
First half	13.6		13.6	$1.60		$1.60
Second half	13.7		13.7	1.60		1.60
12 months	27.3		27.3	1.60		1.60

2009
First half	1.7		1.7	$0.95		$0.95
Second half	1.7		1.7	0.95		0.95
12 months	3.4		3.4	0.95		0.95

	Oil (in Mbbl) Fixed-Price Swaps			Average price per bbl, net to the well
2007
First half	525	199	724	$52.01	$57.91	$53.63
Second half	534	202	736	52.01	57.91	53.63
12 months	1,059	401	1,460	52.01	57.91	53.63

2008
First half	109	73	182	$59.45	$65.45	$61.85
Second half	111	73	184	59.45	65.45	61.85
12 months	220	146	366	59.45	65.45	61.85

As of December 31, 2006, Market Resources held commodity-price hedging contracts covering about 204.2 million MMBtu of natural gas, 1.8 MMbbl of oil and 22.7 million gallons of NGL. A year earlier Market Resources hedging contracts covered 184.4 million MMBtu of natural gas, 2.9 MMbbl of oil and 10.1 million gallons of NGL. Market Resources has also entered into basis-only swaps on an additional 47.7 million Mcf of natural gas. There were no basis-only swaps a year earlier.

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

The following table summarizes changes in the fair value of derivative contracts from December 31, 2005 to December 31, 2006:


	Fixed-Price Swaps	Basis-Only Swaps	Total
	(in millions)
Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2005	($319.1)		($319.1)
Contracts realized or otherwise settled	167.1		167.1
Change in gas and oil prices on futures markets	236.6		236.6
Contracts added	113.4	($1.9)	111.5
Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2006	$198.0	($1.9)	$196.1

A table of the net fai r value of gas- and oil-derivative contracts as of December 31, 2006, is shown below. About 75% of the fair value of all contracts will settle in the next 12 months and the fair value of cash-flow hedges will be reclassified from other comprehensive income:

QUESTAR 2006 FORM 10-K 44


	Fixed-Price Swaps	Basis-Only Swaps	Total
	(in millions)
Contracts maturing by December 31, 2007	$146.3	$ 1.0	$147.3
Contracts maturing between December 31, 2007 and December 31, 2008	40.9	(3.0)	37.9
Contracts maturing between December 31, 2008 and December 31, 2009	10.8	0.1	10.9
Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2006	$198.0	($1.9)	$196.1

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,
	2006	2005
	(in millions)
Net fair value – asset (liability)	$196.1	($319.1)
Value if market prices of gas and oil and basis differentials decline by 10%	327.0	(166.9)
Value if market prices of gas and oil and basis differentials increase by 10%	65.2	(471.4)

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., BP Energy Company, ONEOK Energy Services Company LP, Enterprise Products Operating and Nevada Power Company. Sales to these companies accounted for 27% of Market Resources revenues before elimination of intercompany transactions in 2006, and their accounts were current at December 31, 2006.

Questar Pipeline requests credit support, such as letters of credit and cash deposits, from those companies that pose unfavorable credit risks. All companies posing such concerns were current on their accounts at December 31, 2006. Questar Pipeline’s largest customers include Questar Gas, PacifiCorp, Kerr McGee, EOG Resources and Chevron/Texaco.

Questar Gas requires deposits from customers that pose unfavorable credit risks. No single customer accounted for a significant portion of revenue in 2006.

Interest Rate Risk

The fair value of fixed-rate debt is subject to change as interest rates fluctuate. The Company had $1,033.5 million of fixed-rate long-term debt with a fair value of $1,065.2 million at December 31, 2006. A year earlier the Company had $983.5 million of fixed-rate long-term debt with a fair value of $ 1,041.5 million. If interest rates would have declined 10%, fair value would increase to $1,094.4 million in 2006 and $1,062.6 million in 2005. 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:

Report of Independent Registered Public Accounting Firm

Consolidated Statements of Income, three years ended December 31, 2006

Consolidated Balance Sheets at December 31, 2006 and 2005

Consolidated Statements of Common Shareholders’ Equity, three years ended

QUESTAR 2006 FORM 10-K 45

December 31, 2006

Consolidated Statements of Cash Flows, three years ended December 31, 2006

Notes Accompanying the Consolidated Financial Statements

Financial Statement Schedules:

Valuation and Qualifying Accounts, for the three years ended December 31, 2006

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

QUESTAR 2006 FORM 10-K 46

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Questar Corporation

We have audited the accompanying consolidated balance sheets of Questar Corporation and subsidiaries as of December 31, 2006 and 2005, 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, 2006. 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 and subsidiaries at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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 3 to the financial statements, Questar Corporation and subsidiaries adopted Statement of Financial Accounting Standards No. 123R, Share Based Payment, under the modified prospective phase-in method, effective January 1, 2006, and as discussed in Note 13 to the financial statements, Questar Corporation and subsidiaries also adopted the requirements of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, effective December 31, 2006

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Questar Corporation's internal control over financial reporting as of December 31, 2006, 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 26, 2007 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Salt Lake City, UT

February 26, 2007

QUESTAR 2006 FORM 10-K 47


QUESTAR CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
	Year Ended December 31,
	2006	2005	2004
	(in millions, except per share amounts)
REVENUES
Market Resources	$1,659.4	$1,668.7	$1,053.9
Questar Pipeline	101.7	82.6	67.9
Questar Gas	1,059.1	956.4	759.5
Corporate and other operations	15.4	17.2	20.1
Total Revenues	2,835.6	2,724.9	1,901.4

OPERATING EXPENSES
Cost of natural gas and other products sold	1,223.6	1,371.3	821.8
Operating and maintenance	286.8	262.8	213.6
General and administrative	135.0	123.1	114.2
Production and other taxes	108.7	120.2	90.9
Depreciation, depletion and amortization	308.4	250.3	216.2
Questar Gas rate-refund obligation			4.1
Impairment of California segment of Southern Trails Pipeline		16.0
Exploration	34.4	11.5	9.2
Abandonment and impairment	7.6	7.9	15.8
Total Operating Expenses	2,104.5	2,163.1	1,485.8
Net gain on asset sales	25.3	4.7	0.3
OPERATING INCOME	756.4	566.5	415.9
Interest and other income	12.9	9.0	6.3
Income from unconsolidated affiliates	7.5	7.5	5.1
Net mark-to-market loss on basis-only swaps	(1.9)
Loss on early extinguishment of debt	(1.7)
Interest expense	(73.6)	(69.4)	(68.4)
INCOME BEFORE INCOME TAXES	699.6	513.6	358.9
Income taxes	255.5	187.9	129.6
NET INCOME	$ 444.1	$ 325.7	$ 229.3

EARNINGS PER COMMON SHARE
Basic	$5.20	$ 3.84	$2.74
Diluted	$5.07	$ 3.74	$2.67
Weighted average common shares outstanding
Used in basic calculation	85.5	84.8	83.8
Used in diluted calculation	87.6	87.1	85.7

See notes accompanying the consolidated financial statements

QUESTAR 2006 FORM 10-K 48



QUESTAR CORPORATION
CONSOLIDATED BALANCE SHEETS
	December 31,
	2006	2005
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$ 24.6	$ 13.4
Federal income taxes recoverable	10.0	11.3
Accounts receivable, net	333.3	373.0
Unbilled gas accounts receivable	67.5	86.2
Derivative collateral deposits		5.1
Fair value of derivative contracts	155.5	2.0
Inventories, at lower of average cost or market
Gas and oil storage	77.9	90.7
Materials and supplies	56.9	34.7
Prepaid expenses and other	27.7	30.1
Purchased-gas adjustments		39.8
Deferred income taxes – current		86.7
Total Current Assets	753.4	773.0

Net Property, Plant and Equipment – successful
efforts method of accounting for gas and oil properties	4,091.4	3,427.5

Investment in Unconsolidated Affiliates	37.5	30.7

Other Assets
Goodwill	70.7	71.3
Regulatory assets	32.7	32.8
Intangible pension asset		10.8
Fair value of derivative contracts	49.0
Other noncurrent assets, net	30.0	28.2
Total Other Assets	182.4	143.1

Total Assets	$5,064.7	$4,374.3

QUESTAR 2006 FORM 10-K 49


QUESTAR CORPORATION

	December 31,
	2006	2005
	(in millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term debt	$ 40.0	$ 94.5
Accounts payable and accrued expenses
Accounts and other payables	436.2	444.4
Production and other taxes	68.9	81.5
Questar Gas customer credit balances	31.4	30.8
Interest	14.9	14.5
Total accounts payable and accrued expenses	551.4	571.2
Fair value of derivative contracts	8.2	222.1
Purchase-gas adjustment	34.3
Deferred income taxes - current	35.0
Current portion of long-term debt	10.0
Total Current Liabilities	678.9	887.8

Long-term debt, less current portion	1,022.4	983.2
Deferred income taxes	763.9	624.2
Asset retirement obligations	132.4	78.2
Pension liability	106.0	44.6
Postretirement benefits liability	37.8	16.4
Fair value of derivative contracts	0.2	99.0
Other long-term liabilities	117.6	91.1
Commitments and contingencies – Note 12

COMMON SHAREHOLDERS’ EQUITY
Common stock – without par value; 350.0 shares authorized;
85.9 outstanding at December 31, 2006, and 85.3 outstanding
at December 31, 2005	409.6	383.3
Retained earnings	1,750.2	1,385.8
Accumulated other comprehensive income (loss)	45.7	(219.3)
Total Common Shareholders’ Equity	2,205.5	1,549.8

Total Liabilities and Common Shareholders’ Equity	$5,064.7	$4,374.3

See notes accompanying the consolidated financial statements

QUESTAR 2006 FORM 10-K 50


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, 2004	83.2	$324.8		$ 977.8	($ 41.3)
Common stock issued	1.3	29.1
Common stock repurchased	(0.1)	(4.8)
2004 net income				229.3				$229.3
Dividends paid ($0.85 per share)				(71.4)
Share-based compensation		2.4
Tax benefit from share-based compensation		6.5
Other comprehensive income
Change in unrealized loss on derivatives					(15.2)			(15.2)
Minimum pension liability					(5.5)			(5.5)
Income taxes					7.8			7.8
Total comprehensive income								$216.4
Balances at December 31, 2004	84.4	358.0		1,135.7	(54.2)
Common stock issued	1.1	16.9
Common stock repurchased	(0.2)	(9.7)
2005 net income				325.7				$325.7
Dividends paid ($0.89 per share)				(75.6)
Share-based compensation		4.2
Tax benefit from share-based compensation		13.9
Other comprehensive income
Change in unrealized loss on derivatives					(251.5)			(251.5)
Minimum pension liability					(14.8)			(14.8)
Income taxes					101.2			101.2
Total comprehensive income								$160.6
Balances at December 31, 2005	85.3	383.3		1,385.8	(219.3)
Common stock issued	0.7	10.8
Common stock repurchased	(0.1)	(6.2)
2006 net income				444.1				$444.1
Dividends paid ($0.93 per share)				(79.7)
Share-based compensation		9.7
Tax benefit from share-based compensation		12.0
Other comprehensive income
Change in unrealized gain on derivatives					524.9			524.9
Minimum pension liability