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, 2005

QUESTAR MARKET RESOURCES, INC.

STATE OF UTAH                                        0-30321                                   87-0287750

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

incorporation or organization)                                                          Identification No.)

180 East 100 South, P.O. Box 45601, Salt Lake City, Utah 84145-0601

(801) 324-2600

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

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

Common stock, $1.00 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  [  ]      No  [X]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  [  ]      No  [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  

Yes  [X]      No  [  ]

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

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

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

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

Yes [ ]       No [X]

#

Aggregate market value of the voting common equity held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second quarter (June 30, 2005):  $0.

On February 28, 2006, 4,309,427 shares of the registrant’s common stock, $1.00 par value, were outstanding (all shares are owned by Questar Corporation).

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

TABLE OF CONTENTS

Nature of Business

Questar E&P

Wexpro

Gas Management

Energy Trading

Environmental Matters

Employees

Questar E&P

Wexpro

Gas Management

Energy Trading

Item 10.

DIRECTORS AND EXECUTIVE OFFICERS OF THE

REGISTRANT (omitted)

Item 11.

EXECUTIVE COMPENSATION (omitted)

Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS (omitted)

Item 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS (omitted)

Where You Can Find More Information

Questar Market Resources, Inc. (Market Resources or the Company), is a wholly owned subsidiary of Questar Corporation (Questar). Both Questar and Market Resources file annual, quarterly, and current reports with the Securities and Exchange Commission (SEC). The public may read and copy these reports and any other materials filed with the SEC at its Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549-0213. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC also maintains a website that contains information filed electronically that can be accessed over the Internet at www.sec.gov.

Interested parties can also access financial and other information via Questar’s website at www.questar.com. Questar and Market Resources make available, free of charge, through the website copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to such reports. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC. Questar’s website also contains Statements of Responsibility for Board Committees, Corporate Governance Guidelines and the Business Ethics and Compliance Policy.

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

Forward-Looking Statements

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

Market Resources undertakes no obligation to publicly correct or update the forward-looking statements in this Annual Report, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

Glossary of Commonly Used Terms

B

Billion

bbl

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

basis

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

Btu

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

cash-flow hedge

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

cf

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

cfe

Cubic feet of natural gas equivalents

development well

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

dewpoint

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

dry hole

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

dth

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

dthe

Decatherms of natural gas equivalents

equity production

Production at the wellhead attributed to Company ownership.

exploratory well

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

finding costs

Finding costs are 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 price for NGLs 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 equal the total number of wells or acres in which the Company has a working interest.

hedging

The use of derivative-commodity and interest-rate instruments to reduce financial exposure to commodity price and interest-rate volatility.

infill development drilling

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

lease operating expenses

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

M

Thousand.

MM

Million.

natural gas equivalents

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

natural gas liquids (NGL)

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

net

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

net revenue interest

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

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).

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, 2005

PART I

ITEM 1.  BUSINESS.

Nature of Business

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 sub-holding company with 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 affiliated company, Questar Gas; Questar Gas Management Company (Gas Management) provides midstream field services including natural gas-gathering and processing services for affiliates and third parties; and Questar Energy Trading Company (Energy Trading) markets equity and third-party gas and oil, provides risk-management services, and through its wholly owned limited liability company, Clear Creek Storage Company, LLC, owns and operates an underground natural gas-storage reservoir.

See Note 11 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for financial information concerning Market Resources lines of business that contribute 10% or more of consolidated revenues.

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

#

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 and in the Uinta Basin of Utah. Questar E&P continues to conduct exploratory drilling to determine commerciality of its inventory of undeveloped leaseholds located primarily in the Rocky Mountain region, including the assessment of deeper reservoirs under approximately 143,000 net leasehold acres in the Vermillion Basin of southwest Wyoming and northwestern Colorado. In the Midcontinent, Questar E&P has several active development projects, including an ongoing coalbed methane project in the Arkoma Basin of eastern Oklahoma and an infill development drilling project in the Elm Grove area in northwestern Louisiana. 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 1,480 Bcfe of estimated proved reserves as of December 31, 2005. Approximately 80% of Questar E&P’s proved reserves, or 1,179 Bcfe, were located in the Rocky Mountain region of the United States, while the remaining 20%, or 301 Bcfe, was located in the Midcontinent region. Approximately 920 Bcfe of the proved reserves reported by Questar E&P at year-end 2005 were developed, while 560 Bcfe were proved undeveloped. The majority of the proved undeveloped reserves were associated with the Company’s Pinedale Anticline leasehold. Questar E&P’s primary focus is natural gas. Natural gas comprised about 90% of Questar E&P’s total proved reserves at year-end 2005. See Item 2 in Part I and Note 12 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 pipelines, 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’s 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. During the last two years, Market Resources has been working 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. 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. Some species that are known to be present may be listed under federal law as endangered or threatened. Such listing could have a material impact on access to Market Resources leaseholds in certain areas or during periods when the particular species is present.

Wexpro

Wexpro develops and produces gas and oil on certain properties owned by 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% 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 $206.3 million at December 31, 2005.

Wexpro delivers natural gas production to Questar Gas at a price equal to Wexpro’s cost-of-service. Wexpro cost-of-service gas satisfied 41% of Questar Gas system requirements during 2005 at cost of service pricing that is 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 (pad drilling and multi-stage hydraulic fracture stimulation) have unlocked significant unexploited potential on many of the subject properties. Wexpro has identified $600 to $750 million of additional drilling opportunities that could support high single-digit to low double-digit growth in revenues and net income over the next five to ten years while delivering cost-of-service natural gas supplies to Questar Gas at prices competitive with alternative sources.

See Note 10 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Wexpro Agreement.

Gas Management

Gas Management provides natural gas-gathering and processing services to affiliates and third-party producers in the Rocky Mountain region. Gas Management also owns 50% of Rendezvous Gas Services, LLC, (Rendezvous), a joint venture 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. Under a contract with Questar Gas, Gas Management also gathers cost-of-service volumes produced from properties operated by Wexpro.

Approximately 56% of Gas Management’s revenues are derived from fee-based gathering and processing agreements. The remaining revenues are 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 Clear Creek Storage Company, LLC, operates an underground gas-storage reservoir in southwestern Wyoming. It 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 company production. Energy Trading does not engage in speculative hedging transactions. See Notes 1 and 5 to the consolidated financial statements included in Item 8 and Commodity-Price Risk Management included in Item 7A in Part II of this Annual Report for additional information relating to hedging activities.

Environmental Matters

See Item 3. Legal Proceedings in Part I of this Annual Report for a discussion of the Company’s environmental matters.

Employees

At December 31, 2005, Market Resources had 601 employees compared with 563 at year-end 2004. None of these employees are represented under collective bargaining agreements. The Company also periodically engages independent reservoir-engineering consultants and other technical specialists on a fee basis.

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 the Company’s proved reserves at December 31, 2005, was natural gas, the Company is substantially more sensitive to changes in natural gas prices than to changes in oil prices.

Market Resources cannot predict the future price of natural gas, oil and NGL because of factors beyond its control, including but not limited to:

*

changes in domestic and foreign supply of natural gas, oil and NGL;

*

changes in local, regional, national and global demand for natural gas, oil, and NGL;

*

regional price differences resulting from available pipeline transportation capacity or local demand;

*

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

*

domestic and global economic conditions;

*

domestic political developments;

*

weather conditions;

*

domestic and foreign government regulations and taxes;

*

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

*

the price, availability and acceptance of alternative fuels;

*

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

Market Resources uses derivative instruments to manage exposure to uncertain prices.  Market Resources 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. Market Resources believes its Wexpro subsidiary generates revenues that are not significantly sensitive to short-term fluctuations in commodity prices.

The Company 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 rating 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. 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.

Market Resources 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; 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 oil and gas industry, the Company maintains insurance against some, but not all, of these potential risks and losses. Market Resources 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.

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

The Company 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 tend to 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 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.

Market Resources is dependent on bank credit facilities and continued access to capital markets to successfully execute its operating strategies.  The Company relies on bank borrowing, inter-company loans from Questar and access to public capital markets to finance a material portion of its operating strategies. Questar relies on access to short-term commercial paper markets to make inter-company loans. The Company is dependent on these capital sources to provide capital to acquire and develop properties. The availability and cost of these capital sources is cyclical, and they may not remain available, or the Company may not be able to obtain money at a reasonable cost in the future. All of the Company’s bank loans and short-term loans from Questar are in the form of 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 the Company published by Standard & Poor's and Moody's. A downgrade of these 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.

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

General economic and other conditions impact Market Resources results.  The Company’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 Market Resources.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2.  PROPERTIES.

Questar E&P and Wexpro

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, 2005. The estimates were collectively prepared by Ryder Scott Company, Netherland, Sewell & Associates, Inc. and H. J. Gruy and 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. All reported reserves are located in the United States.

Estimated proved reserves      Natural gas (Bcf)      Oil and NGL (MMbbl)	1,324.8 25.9
Total proved reserves (Bcfe)	1,480.4
Proved developed reserves (Bcfe)	920.5
Estimated future net revenues before future      income taxes (in thousands) (1)	$8,599,579
Standardized measure of discounted net cash      flows (in thousands) (2)	$2,707,072

(1)

Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, using average year-end 2005 prices of $7.80 per Mcf for natural gas and $56.47 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, 2003 through 2005, are summarized below:

Proved Gas and Oil Reserves (Bcfe)*

              Year

Year-End Reserves

Annual Production

Reserve Life (Years)

2003

1,158.7

  92.8

12.5

2004

1,434.0

103.5

13.9

2005

1,480.4

114.2

13.0

*Does not include cost-of-service reserves managed, developed and produced by Wexpro for Questar Gas.

In 2005 gas and oil reserves increased 3%, after production and sales of producing properties, to 1,480.4 Bcfe versus a 24% increase in 2004 to 1,434.0 Bcfe. Questar E&P’s production replacement ratio was 141% in 2005 and 366% in 2004. Net reserve additions, revisions, purchases and sales in place totaled 160.6 Bcfe in 2005 and 378.8 Bcfe in 2004. Questar E&P’s five-year average finding cost of proved reserves per Mcfe was $1.08, $0.83 and $0.84 in 2005, 2004 and 2003, respectively.

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. These non-GAAP measures provide useful information to investors interested in analyzing Market Resources performance, but may not be directly comparable with similar information disclosed by other gas and oil companies.

Questar E&P’s proved reserves by major operating areas at December 31, 2005 and 2004 follow:

	2005		2004
	(Bcfe)	(% of total)	(Bcfe)	(% of total)
Pinedale Anticline	780.0	53%	737.9	51%
Uinta Basin	254.9	17%	272.4	19%
Rockies Legacy	144.4	10%	137.2	10%
Rocky Mountains Total	1,179.3	80%	1,147.5	80%
Midcontinent	301.1	20%	286.5	20%
Questar E&P Total	1,480.4	100%	1,434.0	100%

Reserves – Cost-of-Service. The following table sets forth the estimated cost-of-service proved natural gas reserves, which are managed, developed and produced by Wexpro under the terms of the Wexpro Agreement; and Wexpro’s proved oil reserves. The estimates were made by Wexpro’s reservoir engineers as of December 31, 2005. All reported reserves are located in the United States.

Estimated cost-of-service proved reserves      Natural gas (Bcf)      Oil (MMbbl)	497.3 3.9
Total proved reserves (Bcfe)	520.5
Proved developed reserves (Bcfe)	425.2

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’s contractual return on investment under the Wexpro Agreement is divided between Wexpro and Questar Gas. Therefore, SEC guidelines with respect to standard economic assumptions are not applicable. The SEC anticipated such potential difficulty and provides that companies may give appropriate recognition to differences arising because of the effect of the ratemaking process. Accordingly, Wexpro’s 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 12 of the consolidated financial statements included in Item 8 in Part II of this Annual Report for additional information pertaining to both Questar E&P’s proved reserves and the Wexpro-managed 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, 2005, 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 gas, per barrel of oil and NGL produced, and the production cost per Mcfe for the years ended December 31, 2005, 2004 and 2003, respectively. Production costs include direct lifting costs (labor, repairs and maintenance, materials, supplies and workovers), administrative costs of production offices, insurance and property and severance taxes, but are exclusive of depreciation and depletion applicable to capitalized-lease acquisitions, exploration and development expenditures.

	Year Ended December 31,
	2005	2004		2003
Questar E&P    Volumes produced and sold         Gas (Bcf)         Oil and NGL (MMbbl)	100.0 2.4	89.8 2.3		78.8 2.3
Average realized price (including hedges)         Gas (per Mcf)         Oil and NGL (per bbl)	$ 5.18 41.54	$ 4.18 30.97		$ 3.62 23.39
Production costs (per Mcfe)          Lease operating expense          Production taxes	$ 0.54 0.60	$ 0.50 0.46		$ 0.49 0.34
Production costs	$ 1.14	$ 0.96		$ 0.83
Cost-of-Service (Wexpro-managed)    Volumes produced         Gas (Bcf)         Oil and NGL (MMbbl)	40.0 0.4	38.8 0.4	40.1 0.4

Productive Wells.  The following table summarizes Market Resources productive wells (including the cost-of-service wells managed by Wexpro) as of December 31, 2005. All of these wells are located in the United States:

 Gas

Oil

Total

Productive Wells

Gross

4,215.0

950.0

5,165.0

Net

1,953.9

450.1

2,404.0

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 2005, there were 90 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, 2005. “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, 2005

    Developed (1)

 Undeveloped (2)

   Total

  Gross

Net

Gross

Net

Gross

Net

   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

166,885

120,695

194,147

103,303

361,032

223,998

   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

13,397

16,880

3,843

47,182

17,240

   Kentucky

17,323

6,669

17,323

6,669

   Louisiana

12,634

11,397

1,246

1,126

13,880

12,523

   Michigan

89

8

6,240

1,262

6,329

1,270

   Minnesota

313

104

313

104

   Mississippi

2,904

1,922

965

399

3,869

2,321

   Montana

20,149

8,535

301,379

53,279

321,528

61,814

   Nevada

320

280

680

543

1,000

823

   New Mexico

78,073

54,288

38,462

17,690

116,535

71,978

   North Dakota

4,634

546

146,364

21,781

150,998

22,327

   Ohio

202

43

202

43

   Oklahoma

1,502,162

267,650

83,081

49,927

1,585,243

317,577

   Oregon

43,869

7,671

43,869

7,671

   South Dakota

204,398

107,829

204,398

107,829

   Texas

144,467

60,037

57,651

43,799

202,118

103,836

   Utah

103,045

85,671

226,299

109,665

329,344

195,336

   Washington

26,631

10,149

26,631

10,149

   West Virginia

969

115

969

115

   Wyoming

237,278

152,713

403,661

259,524

640,939

412,237

      Total

2,336,157

787,605

1,831,839

814,543

4,167,996

1,602,148

(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:

	Leasehold Acres Expiring
	Gross	Net
12 Months Ending December 31,
2006	106,580	73,942
2007	72,432	55,107
2008	65,767	44,257
2009	26,260	22,302
2010 and later	188,780	155,026

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:

	Productive			Dry
	2005	2004	2003	2005	2004	2003
Net Wells Completed
-Exploratory	6.1	4.7	3.7	1.5		0.2
-Development	165.2	156.0	132.3	7.4	6.6	9.6
Gross Wells Completed
-Exploratory	9	9	10	4		2
-Development	370	322	282	15	13	19

Gas Management

Gas Management owns 1,381 miles of gathering lines in Utah, Wyoming, Colorado and Oklahoma. 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 221 miles of gathering lines and associated field equipment.

Gas Management owns processing plants that have an aggregate capacity of 424 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.

ITEM 3.  LEGAL PROCEEDINGS.

Market Resources is involved in a variety of pending legal disputes involving commercial litigation arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the outcome of these cases will not have a material adverse effect on financial position, operating results or liquidity.

Grynberg.  Questar affiliates, including Market Resources affiliates, are involved in various pending lawsuits filed by Jack Grynberg, an independent producer. The only active case, 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.) involves qui tam claims filed by Grynberg under the federal False Claims Act and is substantially similar to the other cases filed against pipelines and their affiliates that have been consolidated for discovery and pre-trial motions in Wyoming’s federal district court. The cases involve allegations of industry-wide mismeasurement of natural gas quantities on which royalty payments are due the federal government

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 Grynberg’s allegations were publicly disclosed prior to the filing of his complaint and Grynberg is not the “original source” of the information on which the allegations are based. The Special Master appointed in the case issued a Report and Recommendation to the district court recommending dismissal of the Questar defendants, except for one small entity acquired by Questar Gas after these cases were filed. The district court heard arguments on whether to adopt the Special Master’s Report on December 9, 2005. The district court has not issued a decision. Management is unable to determine a reasonable range of loss, if any, related to this matter.

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.

Beaver Gas Pipeline System.  On April 8, 2005, Kaiser-Francis appealed the trial judge’s order granting Questar E&P’s motion to dismiss the lawsuit filed against it in Kaiser-Francis Oil v. Anadarko Petroleum Corp., Case No. CJ-2003-66518 (Dist. Ct. Okla.). Kaiser-Francis was a co-defendant of Questar E&P in a prior Oklahoma case, Bridenstine v. Kaiser-Francis Oil Co. The original lawsuit was a class action alleging improper royalty payments for wells connected to the Beaver Gas Pipeline System in western Oklahoma which is no longer owned by Market Resources. Questar E&P and Anadarko (as the successor to another company) settled the lawsuit in December 2000 by agreeing to pay a total sum of $22.5 million, of which $16.5 million was allocated to Questar E&P. Kaiser-Francis chose not to settle and was assessed damages, including punitive damages, by a jury. Kaiser-Francis ultimately settled for $82.5 million, plus interest. As part of the settlement, Kaiser-Francis and the plaintiff class agreed to entry of a “superseding judgment” purporting to vacate the punitive damages award against Kaiser-Francis after the Oklahoma Supreme Court had affirmed that award and issued its mandate. Questar E&P and Anadarko have appealed the entry of the superseding judgment to the Oklahoma Supreme Court.

Kaiser-Francis’ current lawsuit claims that Questar E&P and Anadarko were obligated by express and implied indemnities to pay for a portion of the damages assessed in the jury trial and for its legal-defense costs. In dismissing the lawsuit for failure to state a claim, the district judge noted that the jury determined that Kaiser-Francis was involved in a conspiracy to commit fraud and was therefore barred by a doctrine similar to “unclean hands” from seeking indemnity for the judgment. On appeal, Kaiser-Francis contends that it should be allowed to amend its petition to argue that the superseding judgment shields it from the jury’s findings of wrongdoing. In dismissing the case, the trial judge found that the superseding judgment made no difference.  

Environmental Matters.  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 is currently operating the facilities and filing necessary reports in compliance with regulatory requirements. It is discussing the allegations with the EPA and expects that it may be required to pay a civil penalty in excess of $100,000 in conjunction with each order. Potential regulatory violations associated with the timeliness of permit filings for other Gas Management facilities in the Uinta Basin have now been added to the civil penalty discussions with the EPA. These potential violations may yield additional civil penalties of an unknown amount.

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

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

PART II

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

All of the Company’s outstanding shares of common stock, $1.00 par value, are owned by Questar. Information concerning the dividends paid on such stock and the ability to pay dividends is reported in the Statements of Consolidated Shareholder’s Equity and the notes accompanying the consolidated financial statements included in Item 8 of Part II of this Annual Report.

ITEM 6.  SELECTED FINANCIAL DATA.

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

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

SUMMARY

Market Resources net income increased 56% in 2005 compared to 2004 and 43% in 2004 over 2003. Primary factors for the higher income were increases in production, higher realized natural gas, oil and NGL prices, increased gas-gathering and processing volumes and margins, and additions to Wexpro’s investment base. The cumulative effect of implementing SFAS 143, an accounting rule governing the treatment of retirement costs of long-lived assets, reduced Market Resources 2003 earnings by $5.1 million. Following is a comparison of net income by line of business:

	Year Ended December 31, 2005                2004              2003			Change 2005 v. 2004		Change 2004 v. 2003
	(dollars in thousands, except per-share amounts)
NET INCOME (LOSS)
Questar E&P	$172,788	$108,158	$70,403		$64,630		$37,755
Wexpro	43,669	35,303	32,642		8,366		2,661
Gas Management	35,699	21,047	13,333		14,652		7,714
Energy Trading	6,081	903	(388)		5,178		1,291
Total	$258,237	$165,411	$115,990		$92,826		$49,421

RESULTS OF OPERATION

Market Resources operates through 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 affiliated company, 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.

Consolidated Results

Market Resources net income for 2005 was $258.2 million compared with $165.4 million in 2004, a 56% increase, and $116.0 million in 2003. Operating income increased $148.7 million, or 54%, in the year to year comparison due to higher commodity prices and increased natural gas production at Questar E&P, an increased investment base at Wexpro, and increased NGL volumes coupled with improved gas gathering and processing margins at Gas Management. Following is a summary of Market Resources financial and operating results:

	Year Ended December 31,
	2005	2004	2003
	(in thousands)
OPERATING INCOME
Revenues
Natural gas sales	$  517,603	$  375,220	$285,118
Oil and NGL sales	118,633	86,336	67,020
Cost-of-service gas operations	133,204	116,747	100,997
Energy marketing	902,761	506,565	332,927
Gas gathering, processing and other	155,973	100,413	82,946
Total revenues	1,828,174	1,185,281	869,008
Operating expenses
Energy purchases	888,253	499,726	327,401
Operating and maintenance	158,525	113,772	101,642
Production and other taxes	102,200	73,243	53,343
General and administrative	54,584	49,607	44,113
Depreciation, depletion and amortization	173,770	142,688	121,316
Exploration	11,538	9,239	4,498
Abandonment and impairment of gas, oil
and other related properties	7,931	15,758	4,151
Wexpro Agreement – oil-income sharing	6,139	4,702	2,199
Total operating expenses	1,402,940	908,735	658,663
Operating income	$  425,234	$  276,546	$210,345
OPERATING STATISTICS
Questar E&P production volumes
Natural gas (MMcf)	99,959	89,801	78,811
Oil and natural gas liquids (Mbbl)	2,375	2,281	2,324
Total production (Bcfe)	114.2	103.5	92.8
Average daily production (MMcfe)	313	283	254
Average commodity prices, net to the well
Average realized price (including hedges)
Natural gas (per Mcf)	$5.18	$4.18	$3.62
Oil and NGL (per bbl)	$41.54	$30.97	$23.39
Average sales price (excluding hedges)
Natural gas (per Mcf)	$6.92	$5.11	$4.17
Oil and NGL (per bbl)	$51.97	$38.10	$28.47
Wexpro net investment base at December 31, net of depreciation and deferred income taxes (millions)	$206.3	$182.8	$172.8
Natural gas-gathering volumes (thousands of     MMBtu)
For unaffiliated customers	144,978	128,721	114,774
For Questar Gas	43,083	38,997	41,568
For other affiliated customers	68,903	56,958	46,150
Total gathering	256,964	224,676	202,492
Gathering revenue (per MMBtu)	$0.25	$0.22	$0.20
Natural gas and oil-marketing volumes (Mdthe)
For unaffiliated customers	118,499	91,188	76,352
For affiliated customers	91,751	82,526	73,245
Total marketing	210,250	173,714	149,597

Questar E&P

Questar E&P net income increased 60% to $172.8 million in 2005 compared with $108.2 million in 2004 and $70.4 million in 2003. The increases were driven by a combination of higher realized natural gas, oil and NGL prices and increased gas, oil and NGL production volumes.

Questar E&P’s production increased to 114.2 Bcfe in 2005, a 10% increase compared to the year-earlier period. Natural gas is Questar E&P’s primary focus. On an energy-equivalent basis, natural gas comprised approximately 88% of Questar E&P’s production for 2005. A comparison of energy equivalent production by region is shown in the following table:

	Year Ended December 31,
	2005	2004	2003
	(in Bcfe)
Pinedale Anticline	33.2	23.5	15.2
Uinta Basin	25.6	24.8	29.0
Rockies Legacy	16.7	18.0	16.7
Rocky Mountain total	75.5	66.3	60.9
Midcontinent	38.7	37.2	31.9
Total Questar E&P production	114.2	103.5	92.8

Questar E&P production from the Pinedale Anticline in western Wyoming increased 41%

 In 2005 and comprised 29% of Questar E&P total production for the year. Questar E&P completed 40 new wells at Pinedale during 2005.

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

Production from Questar E&P’s Rockies Legacy properties in 2005 was 16.7 Bcfe compared to 18.0 Bcfe during the 2004 period, a 7% decrease. Legacy properties include all of Questar E&P’s Rocky Mountain producing properties other than Pinedale 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.

Midcontinent production was 38.7 Bcfe in 2005 compared to 37.2 Bcfe for the same period of 2004, a 4% increase. The Company continued one-rig-development programs in both the Hartshorne coalbed-methane development project in the Arkoma Basin of eastern Oklahoma and the ongoing infill-development drilling on the Elm Grove properties in northwest Louisiana.

Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. In 2005 the weighted average realized natural gas price for Questar E&P (including the effects of hedging) was $5.18 per Mcf compared to $4.18 per Mcf in 2004, a 24% increase. Realized oil and NGL prices for 2005 averaged $41.54 per bbl compared with $30.97 per bbl during the prior year period, a 34% increase. A comparison of average realized prices by region, including hedges, is shown in the following table:

	Year Ended December 31,
	2005	2004	2003
Natural gas (per Mcf)
Rocky Mountains	$5.01	$3.95	$3.27
Midcontinent	5.49	4.57	4.26
Volume-weighted average	5.18	4.18	3.62
Oil and NGL (per bbl)
Rocky Mountains	$42.08	$30.10	$21.95
Midcontinent	40.25	32.98	27.04
Volume-weighted average	41.54	30.97	23.39

Approximately 83% of Questar E&P’s gas production in 2005 was hedged or pre-sold compared to 76% in 2004. Hedging reduced gas revenues $173.9 million in 2005 and $83.9 million in 2004. Questar E&P also hedged or pre-sold approximately 70% of its 2005 oil production and 66% of its 2004 production. Oil hedges reduced revenues $24.8 million in 2005 and $16.3 million in 2004.

The Company may hedge up to 100 percent of its forecasted production from proved reserves to lock in acceptable returns on invested capital and to protect cash flow and earnings from a decline in commodity prices. During 2005, Questar E&P continued to take advantage of high natural gas and oil prices to add to hedge additional production in 2006, 2007 and 2008. Natural gas and oil hedges as of December 31, 2005, are summarized in Item 7A of Part I of this Annual Report.

Questar E&P’s controllable production cost structure per unit of production (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense and allocated interest expense) increased 9% to $2.23 per Mcfe in 2005 versus $2.05 per Mcfe in 2004 and $1.99 per Mcfe in 2003. Questar E&P’s controllable production cost structure is summarized in the following table:

	Year Ended December 31,
	2005	2004	2003
	(per Mcfe)
Depreciation, depletion and amortization	$1.18	$1.04	$0.98
Lease operating expense	0.54	0.50	0.49
General and administrative expense	0.30	0.30	0.29
Allocated interest expense	0.21	0.21	0.23
Total controllable production costs	$2.23	$2.05	$1.99

Depreciation, depletion and amortization expense rose 13% in 2005 to $1.18 per Mcfe due to the ongoing depletion of older, lower-cost reserves, reserve revisions for the company’s Uinta Basin properties and higher reserve replacement (finding and development) costs. Higher day rates for rigs and other services in core operating areas, along with sharply higher steel prices, resulted in higher drilling and completion costs.  

Production taxes per Mcfe produced were $0.60, $0.46 and $0.34 in 2005, 2004 and 2003, respectively. Increased production taxes were driven by higher gas, oil and NGL sales prices. Most production taxes are based on a fixed percentage of commodity sales prices. Higher lease operating expenses reflect a general increase in well service costs, including costs of contracted services and production-related supplies, increased workover and production enhancement projects and additional production-related costs.

Exploration expense increased $1.9 million in 2005 compared to the 2004. The expense increase was due to increased exploratory seismic acquisition expenditures in the Midcontinent and Uinta Basin.

Questar E&P abandonment and impairment expense 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.

Pinedale Anticline Drilling Activity

As of December 31, 2005, Market Resources operated and had an interest in 144 producing wells on the Pinedale Anticline compared to 104 and 76 at year-end 2004 and 2003, respectively. In August, 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10-acre-density drilling for Lance Pool (combined Lance and Mesaverde formations) 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. On 10-acre density, the company has over 932 potential Lance Pool well locations at Pinedale. Of the 788 locations yet to be drilled, 203 were booked as proved undeveloped at year-end, leaving over 585 locations unbooked. Questar E&P has an average Lance Pool working interest of 59.4% and an average net revenue interest of 47.5% in 873 of the 932 locations. Wexpro has an average Lance Pool working interest of 51.3% in 215 of the 932 locations, resulting in a combined average Lance Pool working interest for Questar E&P and Wexpro of 67.5% in the 932 locations.

On August 19, 2005, Questar E&P reached a total depth of 19,520 feet in the Hilliard Shale at the Stewart Point 15-29 exploratory well. Based on log information and gas shows, Questar E&P identified multiple zones of interest below the Lance Pool at depths from about 16,000 to 19,500 feet, ran casing to total depth and in mid-September commenced hydraulic stimulation and testing. Starting in the lower part of the well, the company pumped three frac stages over a 900 foot interval from 18,541 to 19,434 feet and began flowing the well back to sales on an 18/64 inch choke. During initial flowback, the company measured extrapolated flow rates as high as 10.7 MMcf per day of dry, sweet gas with 10,000 to 12,000 psig flowing casing pressure and an extrapolated rate of about 2,400 barrels per day of frac water. As the flowback continued, the well exhibited steadily declining rates and pressures and, on several occasions, had to be shut in to remove debris plugging the choke. Eventually a combination of very small pieces of shale from the formation, proppant used in the fracs, and chunks of the flow-through frac plugs used to isolate individual stages partially filled the wellbore, blocking the flow of gas to the surface. The vertical extent of the obstruction is currently unknown. Given the very high formation pressures, specialized equipment (a high-pressure snubbing unit) and experienced personnel are required to attempt to circulate out the obstruction inside the wellbore and either reestablish production from the initial test interval, or isolate that interval and move up hole to test additional zones. The Company was not able to secure the right snubbing unit and crew for this operation before cold winter weather would make this operation technically and operationally risky. The resumption of testing of the well will be delayed until the spring of 2006.

Uinta Basin

During 2005, the company drilled or participated in ten horizontal Green River formation oil wells, 54 Wasatch and Upper Mesaverde gas wells, and five deeper Blackhawk and Mancos formation gas wells on its core acreage block.

In December, 2005 Questar E&P completed the Wolf Flat 1P-1-15-19 well, the first well drilled under an Exploration and Development Agreement (EDA) with the Ute Indian Tribe covering 12,557 acres of tribal minerals in the southern Uinta Basin. Questar E&P has a 50% working interest in the Wolf Flat well. The Company also completed acquisition of a 2-D seismic survey covering a portion of the EDA lands and exercised its option to acquire leases on all of the EDA lands. The Ute Indian Tribe has the option to participate in the first well drilled in each section with up to a 50% working interest. On December 31, 2005, the company’s second 100% working interest test well in the Flat Rock prospect located one mile north of the Wolf Flat well, the FR 1P-36-14-19 well, was waiting on completion.

Rockies Legacy

In the Vermillion Basin on the southwestern Wyoming-northwestern Colorado border, Market Resources continues to evaluate the potential of several formations at depths of 10,000 to 15,000 feet under the company’s 143,000 net leasehold acres. As of December 31, 2005, the company had recompleted two older wells, drilled and completed three new wells and was drilling one well, the Canyon Creek 47. The first new well, Alkali Gulch Unit Well No 1, was completed in June 2005 and produced an average of 1.68 MMcf per day from the Baxter, Frontier and Dakota formations during the first 206 days. On December 31, 2005, the well was producing about 1.05 MMcf per day. The second new well, Canyon Creek 41, went to sales on September 21, 2005. During the first 102 days of production, the well averaged about 2.0 MMcf per day from the Baxter and Frontier formations. The well was producing about 1.1 MMcf per day on December 31, 2005. After delays related to mechanical problems, the third new well, Hiawatha Deep Unit No. 5, was completed and turned to sales in mid-November, 2005. During the first 46 days of production, the well averaged 1.2 MMcf per day from the Baxter, Frontier and Dakota formations and was producing about .9 MMcf per day on December 31, 2005. The Company currently plans to drill about 12 new wells in the Vermillion Basin during 2006 and has initiated the process with the Bureau of Land Management (BLM) for a new Environmental Impact Statement covering the potential development of the deeper objectives.

Midcontinent

During 2005, the company continued one-rig development programs at both the Hartshorne coalbed-methane project in the Arkoma Basin of eastern Oklahoma and the infill-development drilling project in the Elm Grove properties in northwestern Louisiana. The company drilled or participated in 38 new Hartshorne wells in 2005. In the Elm Grove area, the Company drilled or participated in 31 new wells in 2005 and estimates that it has a remaining inventory of about 108 locations.

Wexpro

Wexpro’s 2005 net income was $43.7 million compared with $35.3 million in 2004 and $32.6 million in 2003. Wexpro develops and produces gas reserves on behalf of affiliate Questar Gas. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation – investment base. Wexpro invested $57.8 million, boosting its investment base 13% to $206.3 million at December 31, 2005, up $23.5 million over the year earlier. Wexpro’s 2005 net income also benefited from 35% higher realized oil and NGL prices.

Gas Management

Gas Management net income increased 70% to $35.7 million in 2005 from $21.0 million in 2004 and $13.3 million in 2003. Gross keep-whole processing margins (revenue from the sale of extracted NGLs less the cost of natural gas to replace the Btu-equivalent of extracted NGL volumes) grew 22% from $14.2 million in 2004 to $17.4 million in 2005. The first quarter 2005 acquisition of a gas plant in western Wyoming drove a 59% increase in extracted NGL volumes in 2005 versus the year earlier. Gathering volumes increased 32.3 million MMBtu to 257.0 million MMBtu in 2005 due primarily to expanding Pinedale production and new projects serving third parties in the Uinta Basin.

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.) To further reduce margin volatility associated with keep-whole contracts, Gas Management began managing NGL price risk in 2004 by using forward-sales contracts. In 2005 keep-whole contracts benefited from a 19% increase in NGL sales prices versus the prior-year. Fee-based contracts benefited from a $0.02 increase in the rate charged per MMBtu processed in 2005. Forward sales contracts decreased NGL revenues by $1.0 million in 2005.

Earnings before tax from Gas Management’s 50% interest in Rendezvous increased to $7.2 million in 2005 versus $5.0 million for 2004, a 45% increase. Earnings growth in Rendezvous was driven by increased gathering volumes. 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.

During the first quarter of 2005, Gas Management acquired a cryogenic gas processing facility located approximately 13 miles south of Gas Management’s Blacks Fork plant, adding approximately 60 MMcf per day of raw gas processing and NGL extraction capacity at its western Wyoming hub. The plant has been connected to the Blacks Fork/Granger complex to significantly enhance processing and blending capacity for Pinedale, Jonah and other western Wyoming producers served by Gas Management and Rendezvous.

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. These new facilities will eliminate over 25,500 tanker-truck trips per year at peak production from Market Resources operated acreage and the related air emissions, dust, noise, visual and traffic impacts.

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 also signed a letter of intent to form 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

Energy Trading’s net income for 2005 was $6.0 million compared to $0.9 million in 2004 and a loss of $0.4 million in 2003. Gross margins for gas and oil marketing (gross revenues less costs for gas and oil purchases, transportation and gas storage) increased to $14.5 million in 2005 versus $6.8 million a year ago, a 113% increase. The increase in gross margin was due primarily to a 77% higher unit margin and a 21% increase in volumes (includes both equity and third-party) over the same period last year.

INVESTING ACTIVITIES

Capital spending in 2005 amounted $573.1 million. The details of capital expenditures in 2005 and 2004 and a forecast for 2006 are shown in the table below:

	Year Ended December 31,
	2006 Forecast	2005	2004
		(in thousands)
Market Resources
Drilling and other exploration	$  22,800	$ 51,671	$  29,229
Development drilling	331,600	355,116	222,455
Wexpro development drilling	62,900	53,652	39,184
Reserve acquisitions		3,497	1,131
Production	15,800	24,817	13,640
Gathering and processing	52,000	96,733	26,979
Storage		545	1,171
General	5,300	2,881	12,040
	490,400	588,912	345,829
Capital expenditure accruals		(15,806)	(13,023)
Total capital expenditures	$490,400	$573,106	$332,806

Market Resources expanded Rockies, Uinta Basin and Midcontinent drilling programs and construction of the water and condensate gathering system to serve the Pinedale Anticline represented the majority of the increase in capital expenditures for 2005 compared to 2004. Completion of the water and condensate gathering system in 2005 is the primary reason for the decrease in forecast 2006 capital expenditures.

In 2005 Market Resources increased drilling activity at Pinedale and in the Midcontinent region. During 2005 Market Resources participated in 501 wells (180.2 net), resulting in 171.3 net successful gas and oil wells and 8.9 net dry or abandoned wells. The net drilling-success rate was 95.1% in 2005. There were 103 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.

CONTRACTUAL CASH OBLIGATIONS AND OTHER COMMITMENTS

In the course of ordinary business activities, Market Resources enters into a variety of contractual cash obligations and other commitments. The following table summarizes the significant contractual cash obligations as of December 31, 2005:

	Payments Due by Year
	Total	2006	2007-2008	2009-2010	After 2010
	(in millions)
Long-term debt	$350.0		$200.0		$150.0
Transportation and    storage contracts	53.0	$6.9	13.5	$10.8	21.8
Operating leases	9.9	2.3	3.7	2.1	1.8
Total	$412.9	$9.2	$217.2	$12.9	$173.6

CRITICAL ACCOUNTING POLICIES, ESTIMATES AND ASSUMPTIONS

Market Resources significant accounting policies are described in Note 1 accompanying the consolidated financial statements included in Item 8. 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.

Successful Efforts Accounting for Gas and Oil Operations

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

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

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

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

Long-lived assets are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated on a field-by-field basis. If the undiscounted pretax cash flows are less than the net book value of the asset group, the asset value is written down to estimated fair value, which is determined using discounted future net revenues.

Accounting for Derivatives

The Company uses derivative instruments, typically fixed-price swaps, to hedge against a decline in the realized prices of its gas and oil production. Accounting rules for derivatives require that these instruments be marked 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 as gas, oil and NGL is sold to purchasers. Revenues include estimates for the two most recent months using published commodity index prices and volumes supplied by field operators. Revenues also reflect the impact of price-hedging instruments. A liability is recorded to the extent that Questar E&P has sold volumes in excess of its share of remaining gas and oil reserves in an underlying property. Energy Trading gas and oil marketing revenues are presented on a gross-revenue basis.

Recent Accounting Developments

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

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

Market Resources primary market risk exposures arise from commodity price changes for natural gas, oil and NGL, estimation of gas and oil reserves 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-hedging 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. Hedging contracts are used for a significant share of Questar E&P owned gas and oil production and for a portion of gas and oil marketing transactions and for 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 supports Market Resources rate of return and cash-flow targets and protects earnings from downward movements in commodity prices. The volume of hedged production and the mix of derivative instruments are regularly evaluated and adjusted by management in response to changing market conditions 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 equity NGL.

Hedges 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. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. Any ineffective portion of hedges is immediately recognized in income. The ineffective portion of hedges was not significant in 2005 and 2004.

As of December 31, 2005, approximately 142.8 Bcf of forecast gas production for 2006, 2007 and 2008 was hedged at an estimated average price of $6.62 per Mcf, net to the well (which reflects assumed adjustments for regional basis, gathering and processing costs and gas quality).

The Company 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 rating 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. In addition to the counterparty arrangements, Market Resources has a $200 million long-term revolving-credit facility with banks that was not utilized at December 31, 2005.

A summary of Market Resources hedging positions for equity production as of December 31, 2005, is shown below. Prices are net to the well. Currently all hedges are fixed-price swaps with creditworthy counterparties, allowing Market Resources to achieve a known price for a specific volume of production delivered into a regional sales point. The 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)			Average price per Mcf, net to the well
First half of 2006	25.7	11.9	37.6	$5.93	$6.81	$6.21
Second half of 2006	26.1	12.2	38.3	5.93	6.81	6.21
12 months of 2006	51.8	24.1	75.9	5.93	6.81	6.21
First half of 2007	14.7	10.1	24.8	$6.80	$7.82	$7.22
Second half of 2007	14.9	10.3	25.2	6.80	7.82	7.22
12 months of 2007	29.6	20.4	50.0	6.80	7.82	7.22
First half of 2008	5.1	3.3	8.4	$6.36	$7.23	$6.70
Second half of 2008	5.1	3.4	8.5	6.36	7.23	6.70
12 months of 2008	10.2	6.7	16.9	6.36	7.23	6.70
				Estimated
	Oil (in Mbbl)			Average price per bbl, net to the well
First half of 2006	615	200	815	$47.77	$59.89	$50.73
Second half of 2006	626	202	828	47.77	59.89	50.73
12 months of 2006	1,241	402	1,643	47.77	59.89	50.73
First half of 2007	453	181	634	$56.01	$57.08	$56.32
Second half of 2007	460	184	644	56.01	57.08	56.32
12 months of 2007	913	365	1,278	56.01	57.08	56.32

Market Resources held gas price hedging contracts covering the price exposure for about 184.4 million MMBtu of gas, 2.9 MMbbl of oil and 10.1 MMgal of NGL as of December 31, 2005. A year earlier Market Resources hedging contracts covered 135.6 million MMBtu of natural gas, 1.1 MMbbl of oil and 3.8 MMgal of NGL. Market Resources may hedge NGL prices in its processing business.

The following table summarizes changes in the fair value of hedging contracts from December 31, 2004 to December 31, 2005:

	(in thousands)
Net fair value of hedging contracts outstanding at December 31, 2004	($  67,501)
Contracts realized or otherwise settled	54,845
Increase in prices on futures markets	(123,875)
New contracts since December 31, 2004	(182,590)
Net fair value of hedging contracts outstanding at December 31, 2005	($319,121)

A table of the net fair value of hedging contracts as of December 31, 2005, is shown below. About 69% of the fair value of all contracts will settle and be reclassified from other comprehensive income in the next 12 months:

	(in thousands)
Contracts maturing by December 31, 2006	($220,077)
Contracts maturing between December 31, 2006, and December 31, 2007	(78,870)
Contracts maturing between December 31, 2007, and December 31, 2008	(20,174)
Net fair value of hedging contracts at December 31, 2005	($319,121)

The following table shows sensitivity of the mark-to-market valuation of hedging contracts to changes in the market price:

	At December 31,
	2005	2004
	(in millions)
Mark-to-market valuation – asset (liability)	($319.1)	($67.5)
Value if market prices decline by 10%	(166.9)	2.5
Value if market prices increase by 10%	(471.4)	(137.5)

Credit Risk

Market Resources requests credit support and, in some cases, prepayment from companies with unacceptable credit risks. Market Resources five largest customers are BP Energy Company, Nevada Power Company, ONEOK Energy Services Company LP, Coral Energy Resources, LP and Sempra Energy Trading Corp. Sales to these companies accounted for 20% of Market Resources revenues before elimination of intercompany transactions in 2005, and their accounts were current at December 31, 2005.

Interest Rate Risk Management

Market Resources had $350 million of fixed-rate debt with a fair value of $368.5 million and $385.3 million at December 31, 2005 and 2004, respectively. The fair value of fixed-rate debt is subject to change as interest rates fluctuate.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Financial Statements:

Page No.

Consolidated Statements of Income, three years ended December 31, 2005

December 31, 2005

Consolidated Statements of Cash Flows, three years ended December 31, 2005

Financial Statement Schedules:

For the three years ended December 31, 2005

            Valuation and Qualifying Accounts

All other schedules are omitted because they are not applicable or the required information

is shown in the Consolidated Financial Statements or Notes thereto.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholder

Questar Market Resources

We have audited the accompanying consolidated balance sheets of Questar Market Resources, Inc. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial schedule listed in the Index at Item 8. These financial statements and schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.We were not engaged to perform an audit of the Company’s internal control over financial reporting.  Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. 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 Market Resources, Inc. and subsidiaries at December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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 2 to the financial statements, Questar Market Resources and subsidiaries adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003.

/s/ Ernst & Young LLP

Salt Lake City, Utah

February 27, 2006

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2005	2004	2003
	(in thousands)
REVENUES
From unaffiliated customers	$1,668,670	$1,053,854	$751,502
From affiliates	159,504	131,427	117,506
TOTAL REVENUES	1,828,174	1,185,281	869,008
OPERATING EXPENSES
Cost of natural gas and other products sold	888,253	499,726	327,401
Operating and maintenance	158,525	113,772	101,642
Production and other taxes	102,200	73,243	53,343
General and administrative	54,584	49,607	44,113
Depreciation, depletion and amortization	173,770	142,688	121,316
Exploration	11,538	9,239	4,498
Abandonment and impairment of gas,
oil and other related properties	7,931	15,758	4,151
Wexpro Agreement-oil income sharing	6,139	4,702	2,199
TOTAL OPERATING EXPENSES	1,402,940	908,735	658,663
OPERATING INCOME	425,234	276,546	210,345
Interest and other income	6,527	2,240	3,034
Income from unconsolidated affiliates	7,468	5,125	5,008
Interest expense	(30,865)	(27,412)	(28,158)
INCOME BEFORE INCOME TAXES AND
CUMULATIVE EFFECT	408,364	256,499	190,229
Income taxes	150,127	91,088	69,126
INCOME BEFORE CUMULATIVE EFFECT	258,237	165,411	121,103
Cumulative effect of accounting change for asset
retirement obligations, net of income taxes
of $3,049			(5,113)
NET INCOME	$    258,237	$    165,411	$115,990
See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2005	2004
	(in thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$        4,350
Notes receivable from Questar	89,100	$      49,400
Federal income taxes recoverable	14,136
Accounts receivable, net	241,714	165,531
Accounts receivable from affiliates	26,386	19,247
Hedging collateral deposits	5,150
Fair value of hedging contracts	1,972	9,334
Inventories, at lower of average cost or market
Gas and oil storage	33,192	22,604
Material and supplies	24,018	8,631
Prepaid expenses and other	23,348	16,632
Deferred income taxes – current	97,136	33,421
TOTAL CURRENT ASSETS	560,502	324,800
PROPERTY, PLANT AND EQUIPMENT – successful efforts      method of accounting for gas and oil properties
Gas and oil properties
Proved properties	2,047,868	1,602,143
Unproved properties, not being depleted	41,567	62,678
Support equipment and facilities	18,389	16,932
Cost-of-service gas and oil properties	561,501	516,162
Gathering, processing, marketing and other	360,177	258,417
	3,029,502	2,456,332
Less accumulated depreciation, depletion and amortization
Gas and oil properties	731,098	600,366
Cost-of-service gas and oil properties	277,648	262,523
Gathering, processing, marketing and other	86,797	74,378
	1,095,543	937,267
NET PROPERTY, PLANT AND EQUIPMENT	1,933,959	1,519,065
INVESTMENT IN UNCONSOLIDATED AFFILIATES	30,681	33,229
OTHER ASSETS
Goodwill	61,423	61,423
Contract receivable from Questar Gas	4,576	5,097
Fair value of hedging contracts		1,815
Other noncurrent assets	12,952	15,417
	78,951	83,752
	$2,604,093	$1,960,846

LIABILITIES AND SHAREHOLDER’S EQUITY

	December 31,
	2005	2004
	(n thousands)
CURRENT LIABILITIES
Checks in excess of cash balance		$      4,394
Notes payable to Questar	$    180,800	61,200
Accounts payable and accrued expenses
Accounts and other payables	297,408	176,974
Accounts payable to affiliates	3,755	6,372
Production and other taxes	43,383	29,716
Interest	8,417	8,495
Federal income taxes		4,559
Total accounts payable and accrued expenses	352,963	226,116
Fair value of hedging contracts	222,049	64,179
TOTAL CURRENT LIABILITIES	755,812	355,889
LONG-TERM DEBT	350,000	350,000
DEFERRED INCOME TAXES	408,399	346,932
ASSET RETIREMENT OBLIGATIONS	74,273	66,375
FAIR VALUE OF HEDGING CONTRACTS	99,044	14,471
OTHER LONG-TERM LIABILITIES	42,710	38,309
COMMITMENTS AND CONTINGENCIES – Note 7
COMMON SHAREHOLDER’S EQUITY
Common stock – par value $1 per share;
25,000,000 shares authorized; 4,309,427 shares issued        and outstanding	4,309	4,309
Additional paid-in capital	116,027	116,027
Retained earnings	951,621	710,684
Accumulated other comprehensive loss	(198,102)	(42,150)
TOTAL SHAREHOLDER’S EQUITY	873,855	788,870
	$2,604,093	$1,960,846
See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY

				Accumulated		Compre-
		Additional		Other		hensive
	Common	Paid-in	Retained	Comprehensive		Income
	Stock	Capital	Earnings	Loss		(Loss)
	(in thousands)
Balance at January 1, 2003	$4,309	$116,027	$463,883	($ 16,880)
2003 net income			115,990		$115,990
Dividends paid			(17,300)
Other comprehensive loss
Change in unrealized loss on energy
hedges, net of income taxes of $9,429				(15,755)	(15,755)
Balance at December 31, 2003	4,309	116,027	562,573	(32,635)	$100,235
2004 net income			165,411		$165,411
Dividends paid			(17,300)
Other comprehensive loss
Change in unrealized loss on energy
hedges, net of income taxes of $5,677				(9,515)	(9,515)
Balance at December 31, 2004	4,309	116,027	710,684	(42,150)	$155,896
2005 net income			258,237		$258,237
Dividends paid			(17,300)
Other comprehensive loss
Change in unrealized loss on energy
hedges, net of income taxes of $95,467				(155,952)	(155,952)
Balance at December 31, 2005	$4,309	$116,027	$951,621	($198,102)	$102,285
See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2005	2004	2003
	(in thousands)
OPERATING ACTIVITIES
Net income	$258,237	$ 165,411	$ 115,990
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation, depletion and amortization	174,938	147,068	125,673
Deferred income taxes	93,219	68,641	58,839
Abandonment and impairment of gas, oil and other         related properties	7,931	15,758	4,151
Net (gain) loss from asset sales	(884)	(315)	14
Income from unconsolidated affiliates,
net of cash distributions	2,548	3,164	1,974
Other	201	286	(127)
Cumulative effect of accounting change			5,113
Changes in operating assets and liabilities:
Accounts receivable and hedging collateral deposits	(88,472)	(32,555)	(49,754)
Inventories	(25,975)	(10,287)	(9,807)
Prepaid expenses and other	(6,716)	(7,216)	(1,429)
Accounts payable and accrued expenses	115,598	57,454	15,662
Federal income taxes	(18,695)	2,312	(12,068)
Other assets	1,962	(7,079)	(2,309)
Other liabilities	3,419	10,372	6,208
NET CASH PROVIDED FROM OPERATING ACTIVITIES	517,311	413,014	258,130
INVESTING ACTIVITIES
Capital expenditures
Property, plant and equipment	(573,106)	(331,806)	(212,011)
Other investments		(1,000)	(14,750)
	(573,106)	(332,806)	(226,761)
Proceeds from asset dispositions	1,939	2,037	9,053
NET CASH USED IN INVESTING ACTIVITIES	(571,167)	(330,769)	(217,708)
FINANCING ACTIVITIES
Checks in excess of cash balances	(4,394)	4,394
Change in notes receivable from Questar	(39,700)	(42,500)	88,700
Change in notes payable to Questar	119,600	24,700	26,600
Long-term debt issued	200,000
Long-term debt repaid	(200,000)	(55,000)	(145,000)
Other financing		(255)	(110)
Dividends paid	(17,300)	(17,300)	(17,300)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	58,206	(85,961)	(47,110)
Change in cash and cash equivalents	4,350	(3,716)	(6,688)
Beginning cash and cash equivalents	-	3,716	10,404
Ending cash and cash equivalents	$      4,350	$           -	$       3,716

See notes accompanying the consolidated financial statements

QUESTAR MARKET RESOURCES, INC.

NOTES ACCOMPANYING CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies

Nature of Business

Market Resources is a wholly owned subsidiary of Questar. The Company operates through 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 affiliated company, 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.

Principles of Consolidation

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

Investments in Unconsolidated Affiliates

Market Resources uses the equity method to account for investments in affiliates where it does not have control. Generally, the Company’s investment in these affiliates equals the underlying equity in net assets.

Use of Estimates

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

Revenue Recognition

Market Resources subsidiaries recognize revenues in the period that services are provided or products are delivered. Revenues reflect the impact of price-hedging instruments. Revenues associated with the production of gas and oil are accounted for using the sales method, whereby revenue is recognized as gas and oil is sold to purchasers. A liability is recorded to the extent that the company has sold volumes in excess of its share of remaining gas and oil reserves in an underlying property. Market Resources imbalance obligations at December 31, 2005 and 2004, were $2.5 million and $3.0 million, respectively. Energy Trading gas and oil marketing revenues are recognized on a gross basis.

Wexpro Agreement – Oil-Income Sharing

Oil income sharing represents payments made to Questar Gas for its share of the income from oil and NGL products associated with cost-of-service properties pursuant to the Wexpro Agreement. See Note 10 for more information on the Wexpro Agreement.

Regulation of Underground Storage

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

Cash and Cash Equivalents

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

Notes Receivable from Questar

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

Property, Plant and Equipment

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

Gas and oil properties

Questar E&P uses the successful efforts method to account for gas and oil properties. The costs of acquiring leaseholds, drilling development wells, drilling successful exploratory wells, purchasing related support equipment and facilities are capitalized. The costs of unsuccessful exploratory wells are charged to expense when it is determined that such wells have not located proved reserves. Costs of geological and geophysical studies and other exploratory activities are expensed as incurred. Costs of production and general corporate activities are expensed in the period incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected.

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

Cost-of-service gas and oil operations

The successful efforts method of accounting is used for “cost-of-service” gas and oil properties owned by Questar Gas and managed and developed by Wexpro. Cost-of-service gas and oil properties are properties for which the operations and return on investment are subject to the Wexpro Agreement (see Note 10). In accordance with the agreement, production from the gas properties operated by Wexpro is delivered to Questar Gas at Wexpro’s cost of providing this service. That cost includes a return on Wexpro’s investment. Oil produced from the cost-of-service properties is sold at market prices. Proceeds are credited pursuant to the terms of the agreement, allowing Questar Gas to share in the proceeds for the purpose of reducing natural gas rates.

Depreciation, depletion and amortization

Capitalized proved leasehold costs are depleted using the unit-of-production method based on proved reserves on a field basis. All other capitalized costs associated with gas and oil properties are depreciated using the unit-of-production method based on proved developed reserves on a field basis. The Company capitalizes an estimate of the fair value of future abandonment costs, less estimated future salvage values, and depreciates those costs over the life of the related asset. Average depreciation, depletion and amortization rates used in the 12 months ended December 31, were as follows:

	2005	2004	2003
Gas and oil properties, per Mcfe	$1.18	$1.04	$0.98
Cost-of-service gas and oil properties, per Mcfe	0.77	0.69	0.65

Impairment of Long-Lived Assets

Proved gas and oil properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific-asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than its carrying value. Triggering events could include an impairment of gas and oil reserves caused by mechanical problems, a faster-than-expected decline of reserves, lease-ownership issues, and/or an other-than-temporary decline in gas and oil prices. If impairment is indicated, fair value is calculated using a discounted-cash-flow approach. Cash-flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices and operating costs.

Goodwill and Other Intangible Assets

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

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

The Company capitalizes interest costs when applicable. Under provisions of the Wexpro Agreement, the company capitalizes AFUDC on cost-of-service construction projects. The FERC requires the capitalization of AFUDC during the construction period of rate-regulated plant and equipment, such as our underground-gas storage facility. AFUDC amounted to $0.4 million in 2005, $0.2 million in 2004 and $1.1 million in 2003 and is included in Interest and Other Income in the Consolidated Statements of Income.

Hedging Instruments

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

-

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

-

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

-

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

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

Physical Contracts

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

Financial Contracts

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

Credit Risk

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

Bad debt expense amounted to $0.1 million in 2005, zero in 2004 and $0.4 million in 2003. In 2004 there was no bad debt expense recorded and the allowance was reduced. The allowance for bad debt expenses was $2.9 million and $2.8 million at December 31, 2005 and 2004, respectively.

Income Taxes

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

Comprehensive Income

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

Business Segments

Market Resources has four major segments: Questar E&P, Wexpro, Gas Management and Energy Trading. Line-of-business information is presented according to senior management’s basis for evaluating performance considering differences in the nature of products, services and regulation. Certain intersegment sales include intercompany profit.

Recent Accounting Developments

In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143” (SFAS 143). FIN 47 clarifies the term conditional asset retirement obligation as used in SFAS 143 and requires a liability to be recorded if the fair value of the obligation can be reasonably estimated. The types of asset retirement obligations that are covered by FIN 47 are those for which an entity has a legal obligation to perform an asset retirement activity; however, the timing and/or method of settling the obligation are conditional on a future event that may or may not be within the control of the entity. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The adoption of FIN 47 in 2005 did not have a significant impact on Market Resources results of operation or financial position.

In June 2005, the FASB issued SFAS 154, “Accounting Changes and Error Corrections,” a replacement of existing accounting pronouncements. SFAS 154 modifies accounting and reporting requirements when a company voluntarily chooses to change an accounting principle or correct an accounting error. SFAS 154 requires retroactive restatement of prior period financial statements unless it is impractical. Previous accounting guidelines allowed recognition by cumulative effect in the period of the accounting change. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

In July 2005, the FASB issued an exposure draft of a Proposed Interpretation “Accounting for Uncertain Tax Positions,” an Interpretation of FASB Statement 109. The exposure draft seeks to reduce perceived diversity in practice associated with recognition and measurement in the accounting for income taxes. The exposure draft would apply to all tax positions accounted for in accordance with SFAS 109, “Accounting for Income Taxes.” The exposure draft requires that a tax position meet a “probable recognition threshold” for the benefit of the uncertain tax position to be recognized in the financial statements. This threshold is to be met assuming that the tax authorities will examine the uncertain tax position. The exposure draft contains guidance with respect to the measurement of the benefit that is recognized for an uncertain tax position, when that benefit should be derecognized, and other matters. The proposed effective date has been postponed. The Company has not evaluated the potential effect of this proposed change in accounting principle.

Questar has granted and may continue to grant stock based compensation to certain Market Resources employees. In December 2004, the FASB issued Statement 123 (revised 2004), (SFAS 123R), “Share Based Payment,” which replaces SFAS 123 and supersedes APB Opinion 25. SFAS 123R eliminates the alternative to use APB Opinion 25’s intrinsic value method of accounting that was provided in SFAS 123 as originally issued. Pro forma disclosure will no longer be allowed. The effective date for implementation of SFAS 123R is January 1, 2006. Alternative phase-in methods are allowed under SFAS 123R. Questar intends to use the modified prospective phase-in method that requires recognition of compensation costs for all share based payments granted, modified or settled after the date of implementation as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. The Company believes that the modified prospective phase-in method will not have a material effect on the Company’s operating results or financial position.

Reclassifications

Certain reclassifications were made to prior-year consolidated financial statements to conform with the 2005 presentation of gathering and processing revenues and expenses, and current portions of deferred income taxes and production taxes.

Note 2 – Asset Retirement Obligations (ARO)

On January 1, 2003, Market Resources adopted SFAS 143 “Accounting for Asset Retirement Obligations.” SFAS 143 addresses the financial accounting and reporting of the fair value of legal obligations associated with the retirement of tangible long-lived assets. The Company’s ARO applies primarily to plugging and abandonment costs associated with gas and oil wells and certain other properties. The fair value of abandonment costs is estimated and depreciated over the life of the related assets. ARO are adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Changes in asset retirement obligations were as follows:

	2005	2004
	(in thousands)
Balance at January 1,	$66,375	$60,493
Accretion	4,210	2,820
Additions	4,997	3,159
Revisions		695
Retirements and properties sold	(1,309)	(792)
Balance at December 31,	$74,273	$66,375

Wexpro activities are governed by a longstanding agreement with the states of Utah and Wyoming (the Wexpro Agreement). The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is spelled out in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the Public Service Commission of Wyoming (PSCW). Pursuant to the stipulation, Wexpro collects and deposits in trust certain funds related to estimated ARO costs. The funds are used to satisfy retirement obligations as the properties are abandoned. At December 31, 2005, $3.7 million was held in this trust invested in a short-term bond index fund.

Note 3 – Investment in Unconsolidated Affiliates

Market Resources uses the equity method to account for investments in unconsolidated affiliates where the Company does not have control. These entities are engaged in gathering and compressing natural gas and have no debt obligations with third-party lenders. The principal affiliates and the Company’s ownership percentage as of December 31, 2005, were Rendezvous Gas Services, LLC, a limited liability corporation, (50%) and Canyon Creek Compression Company, a general partnership (15%). Operating results representing 100% of these businesses are listed below:

	Year Ended December 31,
	2005	2004	2003
	(in thousands)
Revenues	$21,605	$16,857	$15,916
Operating income	14,529	10,280	9,775
Income before income taxes	14,679	10,312	9,807
Current assets, at end of period	6,405	6,626	5,167
Noncurrent assets, at end of period	63,233	66,010	74,111
Current liabilities, at end of period	2,959	1,338	909
Noncurrent liabilities, at end of period	1,843	1,073	1,589

Note 4 – Debt

Questar makes loans to Market Resources under a short-term borrowing arrangement. Short-term notes payable to Questar amounted to $180.8 million with an interest rate of 4.42 % and $61.2 million with an interest rate of 2.42% at December 31, 2005 and 2004, respectively.

The details of long-term debt are listed in the table below. All notes and the term loan are unsecured obligations and rank equally with all other unsecured liabilities. Market Resources revolving credit agreement had no borrowings outstanding at December 31, 2005 or 2004, but was fully drawn during part of 2005. The credit agreement carries an annual commitment fee of 0.125% of the unused balance. At December 31, 2005, Market Resources could pay dividends of $1.08 billion, without violating the terms of the debt covenants.

	December 31,
	2005			2004
	(in thousands)
7.0% notes due 2007		$200,000	$200,000
7.5% notes due 2011		150,000	150,000
$200 million revolving credit agreement due 2010		-	-
Total long-term debt outstanding	$350,000		$350,000

Maturities of long-term debt for the five years following December 31, 2005, amount to a $200 million repayment due in 2007.

Cash paid for interest was $30.4 million in 2005, $26.9 million in 2004 and $28.5 million in 2003.

Note 5 – Financial Instruments and Risk Management

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

	December 31, 2005		December 31, 2004
	Carrying	Estimated	Carrying	Estimated
	Value	Fair Value	Value	Fair Value
	(in thousands)
Financial assets
Cash and cash equivalents	$   4,350	$   4,350	$          -	$          -
Notes receivable from Questar	89,100	89,100	$49,400	$49,400
Energy-price-hedging contracts	1,972	1,972	11,149	11,149

Financial liabilities
Checks in excess of cash balance	$          -	$          -	$   4,394	$   4,394
Notes payable to Questar	180,800	180,800	61,200	61,200
Long-term debt	350,000	368,501	350,000	385,266
Energy price-hedging contracts	321,093	321,093	78,650	78,650

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

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

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

Gas and oil price-hedging contracts – fair value of the contracts is based on market prices as posted on the NYMEX from the last trading day of the year. Gas hedges are structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness.

Market Resources held gas-price-hedging contracts covering the price exposure for about 184.4 MMBtu of natural gas, 2.9 MMbbl of oil and 10.1 MMgal of NGL as of December 31, 2005. Gas Management uses forward-sales contracts to secure the price received for NGL processed from its plants. About 69% of the fair value of all contracts will settle and be reclassified from other comprehensive income in the next 12 months. A year earlier Market Resources hedging contracts covered the price exposure for about 135.6 million MMBtu of natural gas, 1.1 MMbbl of oil and 3.8 MMgal of NGL.

At December 31, 2005, the Company reported a liability, net of hedging assets, of $319.1 million from hedging activities. The offset to the hedging liability, net of income taxes, was a $198.1 million unrealized loss on hedging activities recorded in other comprehensive loss in the shareholders’ equity section of the consolidated balance sheet. The ineffective portion of hedging transactions recognized in earnings was not significant. The fair-value calculation of gas- and oil-price hedges does not consider changes in the fair value of the corresponding scheduled equity physical transactions, (i.e., the correlation between index price and the price realized for the physical delivery of gas or oil).

Note 6 – Income Taxes

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

	Year Ended December 31,
	2005	2004	2003
	(in thousands)
Federal
Current	$  65,501	$24,015	$11,040
Deferred	71,788	59,539	55,176
State
Current	5,377	(1,569)	(753)
Deferred	7,461	9,103	3,663
	$150,127	$91,088	$69,126

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

	Year Ended December 31,
	2005	2004	2003
		Percentages
Federal income tax statutory rate	35.0	35.0	35.0
State income taxes, net of federal income
tax benefit	2.0	1.9	1.0
Domestic production benefit	(0.3)
Percentage depletion	(0.1)	(0.4)
Other	0.2	(1.0)	0.3
Effective income tax rate	36.8	35.5	36.3

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

	December 31,
	2005	2004
	(in thousands)
Deferred tax liabilities:
Property, plant and equipment	$448,382	$368,691
Deferred tax assets:
Energy price hedging	37,515	4,742
Alternative minimum tax credit carried forward		13,969
Employee benefits and compensation costs	2,468	3,048
Total deferred tax assets	39,983	21,759
Net deferred income taxes	$408,399	$346,932

Deferred income taxes – current:
Energy price hedging	($83,286)	($20,593)
Other	(13,850)	(12,828)
Deferred income taxes – current	($97,136)	($33,421)

Cash paid for income taxes was $73.8 million, $22.6 million, and $23.7 million in 2005, 2004 and 2003, respectively.

Note 7 – Commitments and Contingencies

Market Resources is involved in a variety of pending legal disputes involving commercial litigation arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the outcome of these cases will not have a material adverse effect on financial position, operating results or liquidity. A discussion of legal proceedings can be found in Item 3 of Part I in this Annual Report.

Commitments

Subsidiaries of Market Resources have contracted for firm-transportation and storage services with various pipelines through 2018. Market conditions and competition may prevent full recovery of the cost. Annual payments and the years covered are as follows:

	(in millions)
2006	$6.9
2007	7.1
2008	6.4
2009	5.6
2010	5.2
2011 and thereafter	$21.8

Market Resources rents office space throughout its scope of operations from third-party lessors and leases space in an office building located in Salt Lake City, Utah from an affiliated company that expires October 31, 2007. The minimum future payments under the terms of long-term operating leases for the Company’s primary office locations for the years following December 31, 2005, are as follows:

	(in millions)
2006	$2.3
2007	2.2
2008	1.5
2009	1.1
2010	1.0
2011 and thereafter	1.8

Total rental expense amounted to $2.2 million in 2005, $2.2 million in 2004 and $2.1 million in 2003. Sublease-rental receipts were $11,000 in 2005, $20,000 in 2004 and $111,000 in 2003.

Note 8 – Employee Benefits

Qualified Pension Plan

Certain Market Resources employees are covered by Questar’s defined benefit pension plan. Benefits are generally based on the employee’s age at retirement, years of service and highest earnings in a consecutive 72 semimonthly pay period interval during the 10 years preceding retirement. Questar is subject to and complies with minimum required and maximum allowed annual contribution levels mandated by the Employee Retirement Income Security Act and by the Internal Revenue Code. Subject to the above limitations, Questar intends to fund the qualified retirement plan approximately equal to the yearly expense. Plan assets consist principally of equity securities and corporate and U.S. government debt obligations. A third-party consultant calculates the pension plan projected benefit obligation. Qualified pension expense was $2.8 million in 2005, $2.3 million in 2004 and $1.6 million in 2003.

Market Resources portion of plan assets and benefit obligations can not be determined because the plan assets are not segregated or restricted to meet the Company’s pension obligations. If the Company were to withdraw from the pension plan, the pension obligation for the Company’s employees would be retained by the pension plan. At December 31, 2005 and 2004, Questar’s accumulated benefit obligation exceeded the fair value of plan assets.

Postretirement Benefits Other Than Pensions

Eligible Market Resources employees participate in Questar’s postretirement benefits other than pensions plan. Postretirement health care benefits and life insurance are provided only to employees hired before January 1, 1997. The Company pays a portion of the costs of health care benefits, based on an employee’s years of service, and generally limits payments to 170% of the 1992 contribution. Plan assets consist of equity securities and corporate and U.S. government debt obligations. The Company is amortizing its transition obligation over a 20-year period, which began in 1992. A third party consultant calculates the projected benefit obligation. The cost of postretirement benefits other than pensions was $1.2 million in 2005, $1.4 million in 2004 and $1.4 million in 2003.

The Company’s portion of plan assets and benefit obligations related to postretirement medical and life insurance benefits can not be determined because the plan assets are not segregated or restricted to meet the Company’s obligations. At December 31, 2005 and 2004, Questar’s accumulated benefit obligation exceeded the fair value of plan assets.

Postemployment Benefits

Eligible Market Resources employees participate in Questar’s long-term disability plan. The Company recognizes the net present value of the liability for postemployment benefits, such as long-term disability benefits and health-care and life-insurance costs, when employees become eligible for such benefits. Postemployment benefits are paid to former employees after employment has been terminated but before retirement benefits are paid. The Company accrues both current and future costs. Market Resources postemployment liability was $0.7 million and $0.6 million at December 31, 2005 and 2004, respectively.

Employee Investment Plan  

Market Resources subsidiaries participate in Questar’s Employee Investment Plan, which allows eligible employees to purchase shares of Questar common stock or other investments through payroll deduction. Market Resources subsidiaries match 80% of employees’ pretax purchases up to a maximum of 6% of their qualifying earnings. In addition, each year Market Resources subsidiaries make a nonmatching contribution of $200 to each eligible employee. The Company’s expense equaled its matching contribution of $2.1 million, $1.8 million and $1.5 million for the years ended December 31, 2005, 2004 and 2003, respectively.

Note 9 – Related Party Transactions

Market Resources receives a portion of its revenues from services provided to affiliate Questar Gas. The Company received $159.4 million in 2005, $131.4 million in 2004 and $117.5 million in 2003 for operating cost-of-service gas properties, gathering gas and supplying a portion of gas for resale, among other services provided to Questar Gas. Operation of cost-of-service gas properties is described in Wexpro Agreement (Note 10).

Market Resources pays Questar for certain administrative services. These payments were $13.0 million in 2005, $10.1 million in 2004 and $8.3 million in 2003 and were included in operating and maintenance expenses. Questar allocates the costs based on each affiliate’s proportional share of revenues, net of gas costs; property, plant and equipment; and payroll. Management believes that the allocation method is reasonable.

Market Resources contracted for transportation and storage services with affiliate Questar Pipeline and paid $2.8 million in 2005, $2.2 million in 2004 and $2.5 million in 2003 for these services. Energy Trading markets liquids extracted from Questar Pipeline’s transportation lines and paid $3.6 million in 2005, $5.9 million in 2004 and $3.4 million to purchase the liquids in 2003. Questar InfoComm, a former affiliated company that provided some information technology and communication services to Market Resources was paid $0.2 million in 2005, $0.8 million in 2004 and $1.3 million in 2003.

Market Resources has a lease with Questar for space in an office building located in Salt Lake City, Utah, that expires October 31, 2007. The building is owned by a third party. The third party has a lease arrangement with Questar, which in turn sublets office space to affiliated companies. Market Resources paid $0.8 million in 2005, $0.8 million in 2004 and $0.8 million in 2003.

The Company received interest income from affiliated companies of $0.8 million in 2005, $0.2 million in 2004 and $0.9 million in 2003. Market Resources incurred interest expense to affiliated companies of $3.8 million in 2005, $0.9 million in 2004 and $0.8 million in 2003.

Note 10 – Wexpro Agreement

Wexpro’s operations are subject to the terms of the Wexpro Agreement. The agreement was effective August 1, 1981, and sets forth the rights of affiliate Questar Gas’s utility operations to share in the results of Wexpro’s operations. The agreement was approved by the Public Service Commission of Utah and the PSCW in 1981 and affirmed by the Supreme Court of Utah in 1983. Major provisions of the agreement are as follows.

a.  Wexpro continues to hold and operate all oil-producing properties previously transferred from Questar Gas’s nonutility accounts. The oil production from these properties is sold at market prices, with the revenues used to recover operating expenses and to give Wexpro a return on its investment. The after-tax rate of return is adjusted annually and is approximately 13.1%. Any net income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%.

b.  Wexpro conducts developmental oil drilling on productive oil properties and bears any costs of dry holes. Oil discovered from these properties is sold at market prices, with the revenues used to recover operating expenses and to give Wexpro a return on its investment in successful wells. The after-tax rate of return is adjusted annually and is approximately 18.1%. Any net income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%.

c.  Amounts received by Questar Gas from the sharing of Wexpro’s oil income are used to reduce natural-gas costs to utility customers.

d.  Wexpro conducts gas-development drilling on productive gas properties and bears any costs of dry holes. Natural gas produced from successful drilling is owned by Questar Gas. Wexpro is reimbursed for the costs of producing the gas plus a return on its investment in successful wells. The after-tax return allowed Wexpro is approximately 21.1%.

e.  Wexpro operates natural-gas properties owned by Questar Gas. Wexpro is reimbursed for its costs of operating these properties, including a rate of return on any investment it makes. This after-tax rate of return is approximately 13.1%.

Wexpro’s investment base, net of depreciation and deferred income taxes, and the yearly average rate of return for 2005 and the previous two years are shown in the table below:

	2005	2004	2003
Wexpro’s net investment base (in millions)	$206.3	$182.8	$172.8
Average annual rate of return (after tax)	20.4%	19.7%	19.8%

Note 11 – Operations by Line of Business

Line of business information is presented according to senior management’s basis for evaluating performance including differences in the nature of products, services and regulation. Following is a summary of operations by line of business for the three years ended December 31, 2005:

	Market
	Resources	Interco.	Questar		Gas	Energy
	Consol.	Trans.	E & P	Wexpro	Mgt.	Trading
			(in thousands)
2005
Revenues
From unaffiliated customers	$1,668,670		$   620,610	$    21,652	$   141,495	$  884,913
From affiliated companies	159,504	($618,931)		132,305	13,746	632,384
	1,828,174	(618,931)	620,610	153,957	155,241	1,517,297
Operating expenses
Cost of natural gas and other        products sold	888,253	(617,683)	4,200			1,501,736
Operating and maintenance	158,525	(613)	61,790	11,239	85,189	920
Production and other taxes	102,200		68,682	32,602	709	207
General and administrative	54,584	(635)	33,845	9,961	7,528	3,885
Depreciation, depletion and        amortization	173,770		134,651	26,864	11,346	909
Exploration	11,538		11,171	367
Abandonment and impairment of
gas, oil and related properties	7,931		7,692	239
Wexpro – oil-income sharing	6,139			6,139
Total operating expenses	1,402,940	(618,931)	322,031	87,411	104,772	1,507,657
Operating income	425,234		298,579	66,546	50,469	9,640
Interest and other income	6,527	(26,209)	1,527	789	289	30,131
Income from unconsol. affiliates	7,468		255		7,192	21
Interest expense	(30,865)	26,209	(23,649)	(121)	(3,058)	(30,246)
Income tax expense	(150,127)		(103,924)	(23,545)	(19,193)	(3,465)
Net income	$   258,237		$   172,788	$    43,669	$    35,699	$      6,081
Identifiable assets	$2,604,093		$1,639,495	$  331,240	$  301,824	$  331,534
Investment in unconsol. affiliates	30,681		23		30,331	327
Capital expenditures	573,106		421,075	57,794	93,277	960
2004
Revenues
From unaffiliated customers	$1,053,854		$   448,706	$   17,315	$   87,354	$  500,479
From affiliated companies	131,427	($422,200)	90	115,637	11,589	426,311
	1,185,281	(422,200)	448,796	132,952	98,943	926,790
Operating expenses
Cost of natural gas and other         products sold	499,726	(422,096)	2,232		909	918,681
Operating and maintenance	113,772	(5)	51,860	11,064	49,899	954
Production and other taxes	73,243		47,102	24,847	1,082	212
General and administrative	49,607	(99)	30,641	9,385	6,820	2,860
Depreciation, depletion and         amortization	142,688		107,452	25,031	9,446	759
Exploration	9,239		9,239
Abandonment and impairment of
gas, oil and related properties	15,758		12,968	2,790
Wexpro – oil-income sharing	4,702			4,702
Total operating expenses	908,735	(422,200)	261,494	77,819	68,156	923,466
Operating income	276,546		187,302	55,133	30,787	3,324
Interest and other income	2,240	(25,411)	988	503	318	25,842
Income from unconsol. affiliates	5,125		172		4,953
Interest expense	(27,412)	25,411	(21,679)	(931)	(2,766)	(27,447)
Income tax expense	(91,088)		(58,625)	(19,402)	(12,245)	(816)
Net income	$   165,411		$   108,158	$    35,303	$    21,047	$         903
Identifiable assets	$1,960,846		$1,238,922	$  294,553	$  218,202	$  209,169
Investment in unconsol. affiliates	33,229		128		32,639	462
Capital expenditures	332,806		259,865	38,921	26,308	7,712
2003
Revenues
From unaffiliated customers	$  751,502		$     343,804	$   13,004	$   70,189	$  324,505
From affiliated companies	117,506	($318,121)	90	101,598	10,727	323,212
	869,008	(318,121)	343,894	114,602	80,916	647,717
Operating expenses
Cost of natural gas and other        products sold	327,401	(318,004)	2,593		874	641,938
Operating and maintenance	101,642	(11)	45,547	9,992	45,170	944
Production and other taxes	53,343		31,946	20,479	867	51
General and administrative	44,113	(106)	26,461	8,794	5,677	3,287
Depreciation, depletion and        amortization	121,316		90,753	20,352	9,272	939
Exploration	4,498		4,498
Abandonment and impairment of
gas, oil and related properties	4,151		4,151
Wexpro – oil-income sharing	2,199			2,199
Total operating expenses	658,663	(318,121)	205,949	61,816	61,860	647,159
Operating income	210,345		137,945	52,786	19,056	558
Interest and other income (loss)	3,034	(27,229)	1,098	1,374	(43)	27,834
Income from unconsol. affiliates	5,008		258		4,677	73
Interest expense	(28,158)	27,229	(20,928)	(2,570)	(2,717)	(29,172)
Income tax expense	(69,126)		(43,420)	(18,385)	(7,640)	319
Net income before accounting      change	121,103		74,953	33,205	13,333	(388)
Cumulative effect of accounting
change for asset retirement     obligations	(5,113)		(4,550)	(563)
Net income	$   115,990		$       70,403	$    32,642	$    13,333	($     388)
Identifiable assets	$1,644,344		$     989,655	$  266,987	$  186,253	$201,449
Investment in unconsol. affiliates	36,393		172		35,485	736
Capital expenditures	226,761		156,087	37,362	31,379	1,933

Note 12 – Supplemental Gas and Oil Information (Unaudited)

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

Questar E&P Activities

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

Capitalized Costs

The aggregate amounts of costs capitalized for gas and oil exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below. Future-abandonment costs associated with asset retirement obligations amounted to $27.5 million and $25.0 million at December 31, 2005 and 2004, respectively. These costs are included in proved properties and support equipment and facilities.

	December 31,
	2005	2004
	(in thousands)
Proved properties Unproved properties Support equipment and facilities Accumulated depreciation, depletion and      amortization	$2,047,868	$1,602,143
	41,567	62,678
	18,389	16,932
	2,107,824	1,681,753
	731,098	600,366
	$1,376,726	$1,081,387

Costs Incurred

The costs incurred in gas and oil exploration and development activities are displayed in the table below. The development costs include expenditures to develop a portion of the proved undeveloped reserves reported at the end of the prior year. These costs were $116.7 million, $80.1 million and $55.3 million in 2005, 2004 and 2003, respectively.

	Year Ended December 31,
	2005	2004	2003
	(in thousands)
Property acquisition
Unproved	$  13,656	$  13,346	$   3,779
Proved	3,421	1,205	1,039
Exploration (capitalized and expensed)	49,305	25,059	13,521
Development	379,232	238,012	155,226
Asset retirement obligations	2,547	1,699	1,616
	$448,161	$279,321	$175,181

Results of Operation

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

	Year Ended December 31,
	2005	2004	2003
	(in thousands)
Revenues	$620,610	$448,796	$343,894
Production expenses	130,472	98,962	77,167
Exploration expenses	11,171	9,239	4,498
Depreciation, depletion and amortization	132,288	105,451	88,901
Accretion expense (asset retirement obligations)	2,363	2,001	1,852
Abandonment and impairment of gas, oil and    related properties	7,692	12,968	4,151
Total expenses	283,986	228,621	176,569
Revenues less expenses	336,624	220,175	167,325
Income taxes	126,571	77,502	61,409
Results of operation before corporate overhead,    interest and cumulative effect of accounting change	210,053	142,673	105,916
Cumulative effect of accounting change for asset    retirement obligations			(4,550)
Results of operation before corporate overhead    and interest expenses	$210,053	$142,673	$101,366

Estimated Quantities of Proved Gas and Oil Reserves

Estimates of the Company’s proved gas and oil reserves have been prepared by Ryder Scott Company, Netherland, Sewell & Associates, Inc. and H. J. Gruy and Associates, Inc., independent reservoir engineers, in accordance with the SEC’s Regulation S-X and SFAS 69 “Disclosures about Oil and Gas Producing Activities.” The table below summarizes the changes in the estimated net quantities of proved natural gas, oil and NGL reserves for each of the three years in the period ended December 31, 2005. The quantities reported are based on existing economic and operating conditions at the time the estimates were made. All gas and oil reserves reported are located in the United States. The Company does not have any long-term supply contracts with foreign governments or reserves of equity investees:

			Natural Gas
	Natural Gas	Oil and NGL	Equivalents
	(MMcf)	(Mbbl)	(MMcfe)(a)
Balance at January 1, 2003	950,406	27,170	1,113,426
Revisions of estimates	14,057	445	16,726
Extensions and discoveries	111,575	1,285	119,285
Purchase of reserves in place	2,098	8	2,146
Sale of reserves in place	(152)	(3)	(170)
Production	(78,811)	(2,324)	(92,755)
Balance at December 31, 2003	999,173	26,581	1,158,658
Revisions -
Previous estimates	(16,400)	(786)	(21,113)
Pinedale increased-density(b)	302,613	2,383	316,913
Extensions and discoveries	74,155	1,340	82,193
Purchase of reserves in place	812	5	842
Sale of reserves in place	(21)		(21)
Production	(89,801)	(2,281)	(103,488)
Balance at December 31, 2004	1,270,531	27,242	1,433,984
Revisions -
Previous estimates	11,897	(663)	7,919
Pinedale increased-density(b) (c)	31,457	259	33,005
Extensions and discoveries	110,918	1,395	119,293
Purchase of reserves in place	282	67	681
Sale of reserves in place	(295)	(1)	(301)
Production	(99,959)	(2,375)	(114,206)
Balance at December 31, 2005	1,324,831	25,924	1,480,375
Proved Developed Reserves
Balance at January 1, 2003	540,333	19,942	659,985
Balance at December 31, 2003	612,181	20,504	735,205
Balance at December 31, 2004	680,587	21,293	808,345
Balance at December 31, 2005	792,027	21,416	920,523

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

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

      During the third quarter of 2004, the Company presented detailed reservoir engineering and other data to the Wyoming Oil and Gas Conservation Commission (WOGCC) in conjunction with a request for approval of 20-acre-density development on the Company’s Pinedale leasehold. The WOGCC approved the request, and as a result, for the year ended December 31, 2004, the Company reported a net increase of 295 Bcfe of proved reserves at Pinedale. The net increase was comprised of 333 Bcfe of additions categorized as extensions and discoveries of proved reserves less 16 Bcfe of revisions related to removal of certain previously booked proved undeveloped locations as a result of the increased density, further reduced by 23.5 Bcfe of production.  The majority of the net increase in proved reserves at Pinedale was due to the WOGCC’s approval of 20-acre density development and the associated 20-acre proved undeveloped locations. The Company now realizes it inappropriately categorized these reserve additions in its 2004 Form 10-K as “extensions and discoveries.” After a review of the SFAS 69 standard, the Company believes that additions to proved reserves associated with increased density at Pinedale should have been categorized as “revisions” rather than as “extensions and discoveries.” Accordingly, the table has been revised for 2004 to reflect the appropriate classification. Because of ongoing development of the property, the Company will disclose future revisions to proved reserves associated with Pinedale increased-density drilling separately.

^(c)    On August 9, 2005, the Company requested and the WOGCC approved 10-acre-density drilling at Pinedale. The Company presented detailed reservoir engineering data derived from core measurements, reservoir pressures, and production performance of 10-acre pilot wells that indicates a substantial increase in the estimated original gas-in-place in the Lance Pool reservoirs. As a result of the new information, the Company now estimates that wells drilled on 20-acre density will only recover about 25% of the estimated original gas-in-place in the Lance Pool reservoirs and that 10-acre-density development will be required over most of the Company’s leasehold to maximize the economic recovery of in-place volumes. The area approved for 10-acre-density drilling includes all of the currently estimated productive limits of the Company’s Pinedale leasehold. While the Company has commenced 10-acre-density development drilling on its leasehold, estimated proved undeveloped reserves at Pinedale continue to be based on 20-acre density.

Standardized Measure of Future Net Cash Flows Relating to Proved Reserves

Future net cash flows were calculated at December 31 using year-end prices and known contract-price changes. The year-end prices do not include any impact of hedging activities. The average year-end price per Mcf of proved natural gas reserves was $7.80 in 2005, $5.50 in 2004 and $5.57 in 2003. The average year-end price per barrel of proved oil and NGL reserves combined was $56.47 in 2005, $40.60 in 2004 and $30.45 in 2003. Year-end production costs, development costs and appropriate statutory income tax rates, with consideration of future tax rates already legislated, were used to compute the future net-cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop booked proved undeveloped reserves are $157.3 million, $172.6 million and $155.3 million in 2006, 2007 and 2008, respectively. At the end of this three-year period the Company expects to have evaluated about 63% of the current booked proved undeveloped reserves.

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

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

	Year Ended December 31,
	2005	2004	2003
	(in thousands)
Future cash inflows	$11,791,069	$8,090,022		$6,378,076
Future production costs	(2,327,898)	(1,723,128)		(1,403,893)
Future development costs	(725,694)	(663,051)		(338,245)
Future asset retirement obligations	(137,898)	(104,356)		(96,187)
Future income tax expenses	(2,930,318)	(1,854,458)		(1,514,814)
Future net cash flows	5,669,261	3,745,029		3,024,937
10% annual discount to reflect
timing of net cash flows	(2,962,189)	(1,984,491)		(1,494,924)
Standardized measure of discounted
future net cash flows	$ 2,707,072	$1,760,538		$1,530,013

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

	Year Ended December 31,
	2005	2004	2003
	(in thousands)
Beginning balance	$1,760,538	$1,530,013	$  899,626
Sales of gas and oil produced, net
of production costs	(490,138)	(349,834)	(266,726)
Net changes in prices and
production costs	1,142,242	(37,786)	820,131
Extensions and discoveries, less
related costs	330,382	150,692	235,891
Revisions of quantity estimates	113,339	542,317	33,092
Purchase of reserves in place	3,421	1,205	1,039
Sale of reserves in place	(2,928)	(1,363)	(8,610)
Cost to develop proved undeveloped         reserves	116,654	80,066	55,334
Change in future development	(120,303)	(203,574)	(47,886)
Accretion of discount	176,054	153,001	89,963
Net change in income taxes	(440,268)	(28,968)	(345,600)
Change in production rate	41,385	(161,734)	21,091
Other	76,694	86,503	42,668
Net change	946,534	230,525	630,387
Ending balance	$2,707,072	$1,760,538	$1,530,013

Cost-of-Service Activities

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

Capitalized Costs

Capitalized costs for cost-of-service gas and oil properties net of the related accumulated depreciation and amortization are shown below. Future abandonment costs associated with asset retirement obligations amounted to $9.0 million and $8.8 million at December 31, 2005 and 2004, respectively:

	December 31,
	2005	2004
	(in thousands)
Wexpro	$283,853	$253,639
Questar Gas	14,429	16,054
	$298,282	$269,693

Costs Incurred

Costs incurred by Wexpro for cost-of-service gas and oil-producing activities were $57.0 million, including $0.5 million associated with asset retirement obligations in 2005, $43.6 million, including $0.6 million associated with asset retirement obligations in 2004 and $36.6 million, including $0.3 million associated with asset retirement obligations in 2003.

Results of Operation

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

	Year Ended December 31,
	2005	2004	2003
	(in thousands)
Revenues
From unaffiliated companies	$  21,652	$  17,315	$  13,006
From affiliates – Note A	132,305	115,637	101,596
Total revenues	153,957	132,952	114,602
Production expenses	49,980	40,613	32,670
Depreciation and amortization	24,717	21,038	20,169
Accretion expense (asset retirement obligations)	2,147	3,993	183
Abandonment and impairment of gas and oil properties	239	2,790
Exploration	367
Total expenses	77,450	68,434	53,022
Revenues less expenses	76,507	64,518	61,580
Income taxes	26,801	23,167	22,134
Results of operation before corporate
overhead, interest expenses and
cumulative effect of accounting change	49,706	41,351	39,446
Cumulative effect of accounting change
for asset retirement obligations			(563)
Results of operation before corporate
overhead and interest expense	$  49,706	$41,351	$  38,883

Note A – Primarily represents revenues received from Questar Gas pursuant to the Wexpro Agreement.

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

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

			Natural Gas
	Natural Gas	Oil and NGL	Equivalents
	(MMcf)	(Mbbl)	(MMcfe)
Proved Reserves
Balance at January 1, 2003	419,900	3,739	442,334
Revisions of estimates	24,273	103	24,891
Extensions and discoveries	30,286	187	31,408
Production	(40,088)	(449)	(42,782)
Balance at December 31, 2003	434,371	3,580	455,851
Revisions -
Previous estimates	4,500	42	4,752
Pinedale increased-density(a)	112,655	946	118,331
Extensions and discoveries	18,324	62	18,696
Production	(38,758)	(424)	(41,302)
Balance at December 31, 2004	531,092	4,206	556,328
Revisions-
Previous estimates	(30,870)	(230)	(32,250)
Pinedale increased-density	7,793	56	8,129
Extensions and discoveries	29,207	250	30,707
Production	(39,951)	(404)	(42,375)
Balance at December 31, 2005	497,271	3,878	520,539
Proved Developed Reserves
Balance at January 1, 2003	395,821	3,481	416,707
Balance at December 31, 2003	406,144	3,330	426,124
Balance at December 31, 2004	409,194	3,202	428,406
Balance at December 31, 2005	406,608	3,099	425,202

      ^(a)For the year ended December 31, 2004, the Company reported a net increase of 105.0 Bcfe of proved reserves at Pinedale. The net increase was comprised of 120.1 Bcfe of additions categorized as extensions and discoveries of proved reserves less 1.8 Bcfe of revisions related to removal of certain previously-booked proved undeveloped locations as a result of the increased density, further reduced by 11.4 Bcfe of production. The majority of the net increase in proved reserves at Pinedale was due to the WOGCC’s approval of 20-acre density development and the associated 20-acre proved undeveloped locations. The Company now realizes it inappropriately categorized these reserve additions in its 2004 Form 10-K as “extensions and discoveries.” After a review of the SFAS 69 standard, the Company believes that additions to proved reserves associated with increased density at Pinedale should have been categorized as “revisions” rather than as “extensions and discoveries.” Accordingly, the table has been revised for 2004 to reflect the appropriate classification. Because of ongoing development of the property, the Company will disclose future revisions to proved reserves associated with Pinedale increased-density drilling separately.  

#

QUESTAR MARKET RESOURCES, INC.
Schedule of Valuation and Qualifying Accounts
		Column C	Column D
Column A	Column B	Amounts charged	Deductions for	Column E
Description	Beginning Balance	to expense	accounts written off	Ending Balance
(in thousands)
Year Ended December 31, 2005
Allowance for bad debts	$2,804	$130	$(64)	$2,870
Year Ended December 31, 2004
Allowance for bad debts	4,133	(709)	(620)	2,804
Year Ended December 31, 2003
Allowance for bad debts	3,759	432	(58)	4,133

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

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

ITEM 9A.  CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures.

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

Changes in Internal Controls.

Since the Evaluation Date, there have not been any changes in the Company’s internal controls or other factors during the most recent fiscal quarter that could materially affect such controls.

ITEM 9B.  OTHER INFORMATION.

None.

PART III

The Company, as a wholly owned subsidiary of a reporting company under the Act, is entitled to omit all information requested in Part III, Items 10-13.

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES.

Ernst & Young, LLP, serves as the independent registered public accounting firm for Questar and its subsidiaries including the Company. The following table lists the fees billed by Ernst & Young to Questar for services and the fees billed directly to the Company or allocated to the Company as a member of Questar’s consolidated group:

2005

2004

Audit Fees

$1,139,194

$1,271,038

Market Resources Portion

580,586

601,469

Audit-related Fees

48,500

46,000

Market Resources Portion

23,750

19,570

Tax Fees

9,008

8,937

Market Resources Portion

4,441

3,956

All Other Fees

-

-

Market Resources Portion

-

-

PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

Financial statements and financial statement schedules filed as part of this report are listed in the index included in Item 8. Financial Statements and Supplementary Data of this report.

(b) Exhibits.  The following is a list of exhibits required to be filed as a part of this report in Item 15(b).

Exhibit No.

Description

 3.1.*

Articles of Incorporation dated April 27, 1988 for Utah Entrada Industries, Inc. (Exhibit No. 3.1. to the Company’s Form 10 dated April 12, 2000.)

 3.2.*

Articles of Merger dated May 20, 1988 of Entrada Industries, Inc., a Delaware corporation and Utah Entrada Industries, Inc, a Utah corporation. (Exhibit No. 3.2. to the Company’s Form 10 dated April 12, 2000.)

 3.3.*

Articles of Amendment dated August 31, 1998 changing the name of Entrada Industries, Inc. to Questar Market Resources, Inc. (Exhibit No. 3.3. to the Company’s Form 10 dated April 12, 2000.)

 3.4.*  

Bylaws, as amended effective February 8, 2005.(Exhibit No. 3.4. to the Company’s Annual Report on Form 10-K for 2004.)

 4.1.*

Indenture dated as of March 1, 2001 between Questar Market Resources, Inc. and Bank One, NA, as Trustee for the Company’s Notes. (Exhibit No. 4.01. to the Company’s Current Report on Form 8-K dated March 6, 2001.) ¹

 4.2.*

Credit Agreement dated March 19, 2004 by and among the Company, Bank of America, N.A. and other lenders. (Exhibit No. 4.4. to the Company’s Annual Report on Form 10-K for 2003.)

 4.3.*

First Amendment to Credit Agreement dated October 25, 2004 by and among the Company, Bank of America, N.A. and other lenders. (Exhibit No. 4.5. to the Company’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2004.)

 4.4.*

Second Amendment to Credit Agreement dated August 9, 2005 by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 4.4. to the Company’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005.)

 4.5.*

Third Amendment to Credit Agreement dated September 20, 2005 by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 4.5. to the Company’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005.)

10.1.*

Stipulation and Agreement dated October 14, 1981 executed by Mountain Fuel Supply Company [Questar Gas Company]; Wexpro Company; the Utah Department of Business Regulations, Division of Public Utilities; the Utah Committee of Consumer Services; and the staff of the Public Service Commission of Wyoming. (Exhibit No. 10(a) to Questar Gas Company’s Form 10-K Annual Report for 1981.)

12.

Ratio of earnings to fixed charges.

24.

Power of Attorney.

31.1.

Certification signed by Charles B. Stanley, Questar Market Resources, Inc. President and Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2.

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

32.

Certification signed by Charles B. Stanley and S. E. Parks, Questar Market Resources, Inc. President and Chief Executive Officer and Vice President and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

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

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 10^th day of March, 2006.

QUESTAR MARKET RESOURCES, INC.

   (Registrant)

By:  

/s/C. B. Stanley

            C. B. Stanley

            President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

/s/C. B. Stanley

President and Chief Executive Officer

C. B. Stanley

Director (Principal Executive Officer)

/s/S. E. Parks

Vice President and Chief Financial

S. E. Parks

Officer (Principal Financial Officer)

/s/B. Kurtis Watts

Vice President and Controller

B. Kurtis Watts

(Principal Accounting Officer)

*Keith O. Rattie

Chairman of the Board; Director

*Phillips S. Baker, Jr.

Director

*Teresa Beck

Director

*R. D. Cash

Director

*L. Richard Flury

Director

*James A. Harmon

Director

*Robert E. McKee III

Director

*M. W. Scoggins

Director

*C. B. Stanley

Director

March 10, 2006

*By

/s/C. B. Stanley

           Date

C. B. Stanley, Attorney in Fact

Exhibits List

Exhibit No.

Description

 3.1.*

Articles of Incorporation dated April 27, 1988 for Utah Entrada Industries, Inc. (Exhibit No. 3.1. to the Company’s Form 10 dated April 12, 2000.)

 3.2.*

Articles of Merger dated May 20, 1988 of Entrada Industries, Inc., a Delaware corporation and Utah Entrada Industries, Inc, a Utah corporation. (Exhibit No. 3.2. to the Company’s Form 10 dated April 12, 2000.)

 3.3.*

Articles of Amendment dated August 31, 1998 changing the name of Entrada Industries, Inc. to Questar Market Resources, Inc. (Exhibit No. 3.3. to the Company’s Form 10 dated April 12, 2000.)

3.4.*  

Bylaws, as amended effective February 8, 2005.(Exhibit No. 3.4. to the Company’s Annual Report on Form 10-K for 2004.)

 4.1.*

Indenture dated as of March 1, 2001 between Questar Market Resources, Inc. and Bank One, NA, as Trustee for the Company’s Notes. (Exhibit No. 4.01. to the Company’s Current Report on Form 8-K dated March 6, 2001.) ¹

 4.2.*

Credit Agreement dated March 19, 2004 by and among the Company, Bank of America, N.A. and other lenders. (Exhibit No. 4.4. to the Company’s Annual Report on Form 10-K for 2003.)

 4.3.*

First Amendment to Credit Agreement dated October 25, 2004 by and among the Company, Bank of America, N.A. and other lenders. (Exhibit No. 4.5. to the Company’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2004.)

 4.4.*

Second Amendment to Credit Agreement dated August 9, 2005 by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 4.4. to the Company’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005.)

 4.5.*

Third Amendment to Credit Agreement dated September 20, 2005 by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 4.5. to the Company’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005.)

10.1.*

Stipulation and Agreement dated October 14, 1981 executed by Mountain Fuel Supply Company [Questar Gas Company]; Wexpro Company; the Utah Department of Business Regulations, Division of Public Utilities; the Utah Committee of Consumer Services; and the staff of the Public Service Commission of Wyoming. (Exhibit No. 10(a) to Questar Gas Company’s Form 10-K Annual Report for 1981.)

12.

Ratio of earnings to fixed charges.

24.

Power of Attorney.

31.1.

Certification signed by Charles B. Stanley, Questar Market Resources, Inc. President and Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2.

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

32.

Certification signed by Charles B. Stanley and S. E. Parks, Questar Market Resources, Inc. President and Chief Executive Officer and Vice President and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

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

Exhibit 12.

Questar Market Resources, Inc.

Ratio of Earnings to Fixed Charges

	Year Ended December 31,
	2005	2004	2003
	(dollars in thousands)
Earnings
Income before income taxes	$408,364	$256,499	$190,229
Less company’s share of earnings of
equity investees	(7,468)	(5,125)	(5,008)
Plus distributions from equity investees	10,016	8,290	6,982
Plus minority interest in income		270
Less minority interest loss			(183)
Plus interest expense	30,865	27,412	28,158
Plus interest portion of rental expense	1,090	1,113	1,059
	$442,867	$288,459	$221,237
Fixed Charges
Debt expense	$  30,865	$  27,412	$  28,158
Plus interest portion of rental expense	1,090	1,113	1,059
	$  31,955	$  28,525	$  29,217
Ratio of Earnings to Fixed Charges	13.86	10.11	7.57

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

Exhibit 24.

POWER OF ATTORNEY

We, the undersigned directors of Questar Market Resources, Inc., hereby severally constitute C. B. Stanley and S. E. Parks, and each of them acting alone, our true and lawful attorneys, with full power to them and each of them to sign for us, and in our names in the capacities indicated below, the Annual Report on Form 10-K for 2005 and any and all amendments to be filed with the Securities and Exchange Commission by Questar Market Resources, Inc., hereby ratifying and confirming our signatures as they may be signed by the attorneys appointed herein to the Annual Report on Form 10-K for 2005 and any and all amendments to such report.  

Witness our hands on the respective dates set forth below.  

     Signature

Title

  Date

/s/K. O. Rattie                      

Chairman of the Board

  2-14-06 

K. O. Rattie

/s/C. B. Stanley                   

President and Chief

  2-14-06 

C. B. Stanley

Executive Officer

Director

/s/Phillips S. Baker Jr.         

Director

  2-14-06 

Phillips S. Baker

/s/Teresa Beck                     

Director

  2-14-06 

Teresa Beck

/s/R. D. Cash                        

Director

   2-14-06 

R. D. Cash

/s/L. Richard Flury               

Director

  2-14-06 

L. Richard Flury

/s/James A. Harmon             

Director

   2-14-06 

James A. Harmon

/s/Robert E. McKee, III        

Director

   2-14-06 

Robert E. McKee

/s/M. W. Scoggins              

Director

   2-14-06

M. W. Scoggins

Exhibit 31.1.

CERTIFICATION

I, Charles B. Stanley, certify that:

1.

I have reviewed this report of Questar Market Resources, Inc. on Form 10-K for the period ending December 31, 2005;

2.

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

3.

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

4.

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

a)

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

b)

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

c)

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

5.

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

a)

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

b)

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

March 10, 2006

/s/Charles B. Stanley

Charles B. Stanley

President and Chief

Executive Officer

Exhibit 31.2.

CERTIFICATION

I, S. E. Parks, certify that:

1.

I have reviewed this report of Questar Market Resources, Inc. on Form 10-K for the period ending December 31, 2005;

2.

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

3.

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

4.

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

a)

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

b)

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

c)

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

5.

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

a)

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

b)

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

March 10, 2006

/s/S. E. Parks

S. E. Parks

Vice President and Chief

Financial Officer

Exhibit 32.

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Questar Market Resources, Inc. (the Company) on Form 10-K for the period ending December 31, 2005, as filed with the Securities and Exchange Commission on the date hereof (the Report), Charles B. Stanley, President and Chief Executive Officer of the Company, and S. E. Parks, Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1)

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

(2)

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

QUESTAR MARKET RESOURCES, INC.

March 10, 2006

/s/Charles B. Stanley

Charles B. Stanley

President and Chief Executive Officer

March 10, 2006

/s/S. E. Parks

S. E. Parks

Vice President and Chief

Financial Officer

#