UNITED STATES

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549


FORM 10-K


ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934


For the Year Ended December 31, 2007


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QUESTAR MARKET RESOURCES, INC.

(Exact name of registrant as specified in charter)



STATE OF UTAH

0-30321

87-0287750

(State or other jurisdiction of

incorporation or organization)

(Commission File No.)

(I.R.S. Employer

Identification No.)



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

(Address of principal executive offices)


(801) 324-2600

(Registrant’s telephone number)


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, 2007):  $0.


On January 31, 2008, 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.




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2



TABLE OF CONTENTS

Page No.

Where You Can Find More Information

4

Forward-Looking Statements

4

Glossary of Commonly Used Terms

5



PART I


Item 1.

BUSINESS

Nature of Business

7

Exploration and Production

8

    Questar E&P

8

    Wexpro

8

Midstream Field Services – Questar Gas Management

9

Energy Marketing – Questar Energy Trading

10

Environmental Matters

10

Employees

10


Item 1A.

RISK FACTORS

10


Item 1B.

UNRESOLVED STAFF COMMENTS

14


Item 2.

PROPERTIES

Exploration and Production

14

     Questar E&P

14

     Wexpro

14

Midstream Field Services – Questar Gas Management

17

Energy Marketing – Questar Energy Trading

18


Item 3.

LEGAL PROCEEDINGS

18


Item 4.

SUBMISSION OF MATTERS TO A VOTE OF

SECURITY HOLDERS (omitted)

18



PART II



Item 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED

STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY

SECURITIES

18


Item 6.

SELECTED FINANCIAL DATA (omitted)

19


Item 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATION

19


Item 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT

MARKET RISK

26


Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

30




QUESTAR MARKET RESOURCES 2007 FORM 10-K

3



Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

58


Item 9A(T).

CONTROLS AND PROCEDURES

58


Item 9B.

OTHER INFORMATION

59


PART III


Item 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

(omitted)

59


Item 11.

EXECUTIVE COMPENSATION (omitted)

59


Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND

MANAGEMENT AND RELATED STOCKHOLDER MATTERS (omitted)

59


Item 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

AND DIRECTOR INDEPENDENCE (omitted)

59


Item 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

59


PART IV


Item 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

59


SIGNATURES

61


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




QUESTAR MARKET RESOURCES 2007 FORM 10-K

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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 the Company’s 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 web site to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.


Glossary of Commonly Used Terms


B

Billion.

bbl

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

basis

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

basis-only swap

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

Btu

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

cash flow hedge

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

cf

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

cfe

Cubic feet of natural gas equivalents.

development well

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

dewpoint

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

dry hole

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

dth

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




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dthe

Decatherms of natural gas equivalents.

equity production

Production at the wellhead attributed to Questar ownership.

exploratory well

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

frac spread

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

futures contract

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

gal

U.S. gallon.

gas

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

gross

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

hedging

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

infill development drilling

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

lease operating expenses

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

M

Thousand.

MM

Million.

natural gas equivalents

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

natural gas liquids (NGL)

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

net

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

net revenue interest

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

proved reserves

Those quantities of natural gas, crude oil, condensate and NGL on a net revenue interest basis, which geological and engineering data demonstrate with reasonable certainty to be recoverable under existing economic and operating conditions. See 17 C.F.R. Section 4-10(a)(2) for a complete definition.

proved developed reserves

Reserves that include proved developed producing reserves and proved developed nonproducing reserves. See 17 C.F.R. Section 4-10(a)(3).

proved developed producing reserves

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

proved undeveloped reserves

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




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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, 2007


PART I


ITEM 1.  BUSINESS.


Nature of Business


Questar Market Resources, Inc. (Market Resources or the Company) is a natural gas-focused energy company, a wholly-owned subsidiary of Questar Corporation (Questar) and Questar’s primary growth driver. Market Resources is a subholding company with three major lines of business – gas and oil exploration and production, midstream field services, and energy marketing – which are conducted through its four principal subsidiaries:


·

Questar Exploration and Production Company (Questar E&P) acquires, explores for, develops and produces natural gas, oil, and NGL;

·

Wexpro Company (Wexpro) manages, develops and produces cost-of-service reserves for gas utility affiliate, Questar Gas;

·

Questar Gas Management Company (Gas Management) provides midstream field services including natural gas-gathering and processing services for affiliates and third parties; and

·

Questar Energy Trading Company (Energy Trading) markets equity and third-party gas and oil, provides risk-management services, and owns and operates an underground gas-storage reservoir.


Market Resources operates in the Rocky Mountain and Midcontinent regions of the United States of America and is headquartered in Salt Lake City, Utah. Principal offices are located in Denver, Colorado; Oklahoma City, Oklahoma; Tulsa, Oklahoma; and Rock Springs, Wyoming.

 

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







QUESTAR MARKET RESOURCES 2007 FORM 10-K

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[qmr10k4q2007004.gif]


See Note 12 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for financial information by line of business including, but not limited to, revenues from unaffiliated customers, operating income and identifiable assets. A discussion of each of the Company’s lines of business follows.


Exploration and Production – Questar E&P and Wexpro


General: Market Resources’ exploration and production business is conducted through Questar E&P and Wexpro. Exploration and production generated approximately 83% of the Company’s operating income in 2007. Questar E&P operates in two core areas – the Rocky Mountain region of Wyoming, Utah and Colorado and the Midcontinent region of Oklahoma, Texas and Louisiana. Questar E&P has a large inventory of identified development drilling locations, primarily on the Pinedale Anticline in western Wyoming, in the Uinta Basin of Utah and in the Elm Grove area of northwestern Louisiana. Questar E&P continues to conduct exploratory drilling to determine the commerciality of its inventory of undeveloped leaseholds located primarily in the Rocky Mountain region. Questar E&P seeks to maintain geographical and geological diversity with its two core areas. Questar E&P has in the past and may in the future pursue acquisition of producing properties throu gh 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 1,867.6 Bcfe of estimated proved reserves as of December 31, 2007. Approximately 80% of Questar E&P’s proved reserves, or 1,493.7 Bcfe, were located in the Rocky Mountain region of the United States, while the remaining 20%, or 373.9 Bcfe, were located in the Midcontinent region. Approximately 1,147.4 Bcfe of the proved reserves reported by Questar E&P at year-end 2007 were developed, while 720.2 Bcfe were proved undeveloped. The majority of the proved undeveloped reserves were associated with the Company’s Pinedale Anticline leasehold. Natural gas comprised about 89% of Questar E&P’s total proved reserves at year-end 2007. See Item 2 of Part I and Note 15 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company’s proved reserves.


Wexpro develops and produces gas and oil on certain properties for affiliate Questar Gas under the terms of a long-standing comprehensive agreement with the states of Utah and Wyoming, the Wexpro Agreement. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19-20% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation – its investment base. The term of the Wexpro Agreement coincides with the productive life of the gas and oil properties covered therein. Wexpro’s investment




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base totaled $300.4 million at December 31, 2007. See Note 11 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Wexpro Agreement.


Wexpro delivers natural gas production to Questar Gas at a price equal to Wexpro’s cost-of-service. Cost-of-service gas satisfied 34% of Questar Gas supply requirements during 2007 at prices that were significantly lower than Questar Gas paid for purchased gas. Wexpro owns oil-producing properties. Under terms of the Wexpro Agreement, revenues from crude-oil sales offset operating expenses and provide Wexpro with a return on its investment. Any remaining revenues, after recovery of expenses and Wexpro’s return on investment, are divided between Wexpro (46%) and Questar Gas (54%).


Wexpro’s cost of service operations are contractually limited to a finite set of properties set forth in the Wexpro Agreement. Advances in technology (increased density drilling and multi-stage hydraulic fracture stimulation) have unlocked significant unexploited potential on many of the subject properties. Wexpro has identified over $1 billion of additional drilling opportunities that could support high single-digit to low double-digit growth in revenues and net income over the next five to ten years while delivering cost-of-service natural gas supplies to Questar Gas at prices competitive with alternative sources.


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


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


Wexpro collected 88% of its 2007 revenues from affiliated companies, primarily Questar Gas.


Regulation: Exploration and production operations are subject to various government controls and regulation at the federal, state and local levels. Questar E&P must obtain permits to drill and produce; maintain bonding requirements to drill and operate wells; submit and implement spill-prevention plans; and file notices relating to the presence, use, and release of specified contaminants incidental to gas and oil production. Questar E&P is also subject to various conservation matters, including the regulation of the size of drilling and spacing units, the number of wells that may be drilled in a unit and the unitization or pooling of gas and oil properties. Wexpro gas- and oil-development and production activities are subject to the same type of regulation as Questar E&P. In addition, the Utah Division of Public Utilities has oversight responsibility and retains an outside reservoir-engineering consultant and a financial auditor to assess the prudence of Wexpro ’s activities.


Most Questar E&P leases in the Rocky Mountain area are granted by the federal government and administered by federal agencies, principally the Bureau of Land Management (BLM). Current federal regulations restrict activities during certain times of the year on portions of both Market Resources leaseholds due to wildlife activity and/or habitat. Development of Pinedale leasehold acreage is subject to the terms of certain winter-drilling restrictions. In 2004, Market Resources worked with federal and state officials in Wyoming to obtain authorization for limited winter-drilling activities and has developed measures, such as drilling multiple wells from a single pad location, to minimize the impact of its activities on wildlife and wildlife habitat. Various wildlife species inhabit Market Resources leaseholds at Pinedale and in other areas. The presence of wildlife, including species that are protected under the federal Endangered Species Act could limit access to leases held by Market Resources on public lands. The BLM is currently preparing a Supplemental Environmental Impact Statement (SEIS) to consider expanded winter-drilling and completion operations on the Pinedale Anticline. The BLM’s Record of Decision on the SEIS, expected in mid-2008, could significantly impact the pace of development on the Market Resources acreage.


Midstream Field Services – Questar Gas Management


General: Gas Management and its partnerships, generated approximately 13% of the Company’s operating income in 2007. Gas Management owns 50% of Rendezvous Gas Services, LLC, (Rendezvous), a partnership that operates gas-gathering facilities in western Wyoming. Rendezvous gathers natural gas for Pinedale Anticline and Jonah field producers for delivery to various interstate pipelines. Gas Management also owns 38% of Uintah Basin Field Services LLC (Field Services) and 50% of Three Rivers Gathering, LLC (Three Rivers) partnerships that operate gas-gathering facilities in eastern Utah. The FERC-regulated Rendezvous Pipeline Co., LLC (Rendezvous Pipeline), a wholly-owned subsidiary of Gas Management, operates a 21-mile 20-inch-diameter pipeline between Gas Management’s Blacks Fork gas-processing plant and Kern River Gas Transmission Co.’s Muddy Creek compressor station.




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Fee-based gathering and processing revenues were 74% of Gas Management’s net operating revenues during 2007. Approximately 31% of Gas Management’s 2007 net gas-processing revenues were derived from fee-based processing agreements. The remaining revenues were derived from natural gas processing margins that are in part exposed to the frac spread. To reduce processing margin risk, Gas Management has restructured many of its processing agreements with producers from “keep-whole” contracts to “fee-based” contracts. A keep-whole contract insulates producers from frac-spread risk while a fee-based contract eliminates commodity price risk for the processing-plant owner. To further reduce volatility associated with keep-whole contracts, Gas Management may enter into forward-sales contracts for NGL or hedge NGL prices and equivalent gas volumes with the intent to lock in a processing margin. Under a contract with Questar Gas, Gas Management also gathers cost-of-serv ice volumes produced from properties operated by Wexpro.


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


Energy Marketing – Questar Energy Trading


General: Energy Trading markets natural gas, oil and NGL. It combines gas volumes purchased from third parties and equity production to build a flexible and reliable portfolio. As a wholesale marketing entity, Energy Trading concentrates on markets in the Rocky Mountains, Pacific Northwest and Midcontinent that are either close to affiliate reserves and production or accessible by major pipelines. Energy Trading contracts for firm-transportation capacity on pipelines and firm-storage capacity at Clay Basin, a large baseload-storage facility owned by affiliate Questar Pipeline. Energy Trading, through its subsidiary Clear Creek Storage Company, LLC, operates an underground gas-storage reservoir in southwestern Wyoming. Energy Trading uses owned and leased-storage capacity together with firm-transportation capacity to take advantage of price differentials and arbitrage opportunities. Energy Trading generated approximately 4% of the Company’s operating income in 2007.


Competition and Customers: Energy Trading sells equity crude-oil production to refiners, remarketers and other companies, including some with pipeline facilities near company producing properties. In the event pipeline facilities are not available, Energy Trading transports crude oil by truck to storage, refining or pipeline facilities. Energy Trading uses derivatives to manage commodity price risk. Energy Trading primarily uses fixed-price swaps to secure a known price for a specific volume of production. Energy Trading does not engage in speculative hedging transactions. See Notes 1 and 6 to the consolidated financial statements included in Item 8 and Item 7A of Part II of this Annual Report for additional information relating to hedging activities.


Environmental Matters


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


Employees


At December 31, 2007, Market Resources had 775 employees compared with 679 a year earlier.


ITEM 1A.  RISK FACTORS.


Investors should read carefully the following factors as well as the cautionary statements referred to in “Forward-Looking Statements” herein. If any of the risks and uncertainties described below or elsewhere in this Annual Report actually occur, the Company’s business, financial condition or results of operations could be materially adversely affected.


Risks Inherent in the Company’s Business


The future prices for natural gas, oil and NGL are unpredictable. Historically natural gas, oil and NGL prices have been volatile and will likely continue to be volatile in the future. U.S. natural gas prices in particular are significantly influenced by weather. Any significant or extended decline in commodity prices would impact the Company’s future financial condition, revenues, operating results, cash flows, returns on invested capital, and rate of growth. Because approximately 89% of Market Resources’ proved reserves at December 31, 2007, were natural gas, the Company’s revenues, margins, cash flow, net income and return on invested capitals are substantially more sensitive to changes in natural gas prices than to changes in oil prices.





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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;

conservation efforts;

the price, availability and acceptance of alternative fuels;

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

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


The Company may not be able to economically find and develop new reserves. The Company’s profitability depends not only on prevailing prices for natural gas, oil and NGL, but also its ability to find, develop and acquire gas and oil reserves that are economically recoverable. Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics. Because of the high-rate production decline profile of several of the Company’s producing areas, substantial capital expenditures are required to find, develop and acquire gas and oil reserves to replace those depleted by production.


Gas and oil reserve estimates are imprecise and subject to revision. Questar E&P’s proved natural gas and oil reserve estimates are prepared annually by independent reservoir-engineering consultants. Gas and oil reserve estimates are subject to numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and timing of development expenditures. The accuracy of these estimates depends on the quality of available data and on engineering and geological interpretation and judgment. Reserve estimates are imprecise and will change as additional information becomes available. Estimates of economically recoverable reserves and future net cash flows prepared by different engineers, or by the same engineers at different times, may vary significantly. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition, the estimation process also in volves economic assumptions relating to commodity prices, production costs, severance and other taxes, capital expenditures and remedial costs. Actual results most likely will vary from the estimates. Any significant variance could reduce the estimated future net revenues from proved reserves and the present value of those reserves.


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


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


Gas and oil operations involve numerous risks that might result in accidents and other operating risks and costs. Drilling is a high-risk activity. Operating risks include: fire, explosions and blow-outs; unexpected drilling conditions such as abnormally pressured formations; abandonment costs; pipe, cement or casing failures; environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids (including groundwater contamination). The Company could incur




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substantial losses as a result of injury or loss of life; pollution or other environmental damage; damage to or destruction of property and equipment; regulatory investigation; fines or curtailment of operations; or attorney’s fees and other expenses incurred in the prosecution or defense of litigation.


There are also inherent operating risks and hazards in the Company’s gas and oil production, gas gathering, processing, transportation and distribution operations that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites could increase the level of damages resulting from these risks. Certain segments of the Company’s pipelines run through such areas. In spite of the Company’s precautions, an event could cause considerable harm to people or property, and could have a material adverse effect on the financial position and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to the Com pany’s customers. Such circumstances could adversely impact the Company’s ability to meet contractual obligations and retain customers.


As is customary in the gas and oil industry, the Company maintains insurance against some, but not all, of these potential risks and losses. Questar cannot assure that insurance will be adequate to cover these losses or liabilities. Losses and liabilities arising from uninsured or underinsured events could have an adverse effect on the Company’s financial condition and operations.


Market Resources is dependent on bank credit facilities and continued access to capital markets to successfully execute its operating strategies .Market Resources also relies on access to short-term commercial paper markets. The Company is dependent on these capital sources to provide financing for certain projects. The availability and cost of these credit sources is cyclical, and these capital sources may not remain available or the Company may not be able to obtain money at a reasonable cost in the future. All of Market Resources’ bank loans are floating-rate debt. From time to time the Company may use interest-rate derivatives to fix the rate on a portion of its variable-rate debt. The interest rates on bank loans are tied to debt credit ratings of Market Resources and its subsidiaries published by Standard & Poor’s and Moody’s. A downgrade of credit ratings could increase the interest cost of debt and decrease future availability of money fro m 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.


Risks Related to Strategy


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 for 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.


A significant portion of Market Resources production, revenue and cash flow is derived from assets that are concentrated in a Rocky Mountain region. While geographic concentration of assets provides scope and scale that can reduce operating costs and provide other operating synergies, asset concentration does increase exposure to certain risks. Market Resources has extensive operations on the Pinedale Anticline and in the Greater Green River Basin of southwestern Wyoming and in the Uinta Basin of eastern Utah. Any circumstance or event that negatively impacts the operations of Questar E&P, Wexpro or Gas Management in that area could materially reduce earnings and cash flow.


Market Resources uses derivative arrangements to manage exposure to uncertain prices. Market Resources uses commodity-price derivative arrangements to reduce, or hedge, exposure to volatile natural gas, oil, and NGL prices and to protect cash flow, returns on capital, net income and credit ratings from downward commodity price movements. To the extent the Company hedges commodity price exposure, it forgoes the benefits of commodity price increases. Market Resources’ Wexpro subsidiary generates revenues that are not significantly sensitive to short-term fluctuations in commodity prices.


Market Resources enters into commodity-price derivative arrangements with creditworthy counterparties (banks and energy-trading firms) that do not require collateral deposits. The amount of credit available may vary depending on the credit ratings assigned to the Company’s debt securities. A downgrade in the Company’s credit ratings to sub-investment grade could result in the acceleration of obligations to hedge counterparties.





QUESTAR MARKET RESOURCES 2007 FORM 10-K

12


Market Resources may be subject to risks in connection with acquisitions. The acquisition of gas and oil properties requires the assessment of recoverable reserves; future gas and oil sales prices and basis, differentials; operating costs; and potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain. In connection with these assessments, the Company performs a review of the subject properties and pursues contractual protection and indemnification generally consistent with industry practices.


Risks Related to Regulation


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.


Market Resources must comply with numerous and complex regulations governing activities on federal and state lands in the Rocky Mountain region, notably the National Environmental Policy Act, the Endangered Species Act, the Clean Air Act, the Clean Water Act and the National Historic Preservation Act. Federal and state agencies frequently impose conditions on the Company’s activities. These restrictions have become more stringent over time and can limit or prevent exploration and production on the Company’s Rockies leasehold. Certain environmental groups oppose drilling on some of Market Resources’ federal and state leases. These groups sometimes sue federal and state agencies for alleged procedural violations in an attempt to stop, limit or delay natural gas and oil development on public lands.


Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations include such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. One or more of these factors may increase the Company’s costs of doing business on Native American tribal lands and have an impact on the viability of its gas and oil exploration, production, gathering, processing and transportation operations on such lands.


Market Resources may be exposed to certain regulatory and financial risks related to climate change. Many scientists believe that carbon dioxide emissions related to the use of fossil fuels may be causing changes in the earth’s climate. Federal and state courts and administrative agencies are considering the scope and scale of climate-change regulation under various laws pertaining to the environment, energy use and development, and greenhouse gas emissions. Market Resources’ ability to access and develop new natural gas reserves may be restricted by climate-change regulation. There are numerous bills pending in Congress that would regulate greenhouse gas emissions through a cap-and-trade system under which emitters would be required to buy allowances for offsets of emissions of greenhouse gases. In addition, several of the states in which Market Resources operates are considering various greenhouse gas registration and reduction programs. Carbon dioxide r egulation could increase the price of natural gas, restrict access to or the use of natural gas, and/or reduce natural gas demand. Federal, state and local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for natural gas. While future climate-change regulation is likely, it is too early to predict how this regulation will affect Market Resources’ business, operations or financial results.


Other Risks


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




QUESTAR MARKET RESOURCES 2007 FORM 10-K

13


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.


Exploration and Production


Reserves – Questar E&P

The following table sets forth Questar E&P’s estimated proved reserves as of December 31, 2007. The estimate was collectively prepared by Ryder Scott Company, H. J. Gruy and Associates, Inc. and Netherland, Sewell & Associates, Inc., independent reservoir-engineering consultants. Questar E&P does not have any long-term supply contracts with foreign governments or reserves of equity investees or of subsidiaries with a significant minority interest. At December 31, 2007, approximately 91% of Questar E&P’s estimated proved reserves were Company operated. All reported reserves are located in the United States.


Estimated proved reserves

 

  Natural gas (Bcf)

1,668.5 

  Oil and NGL (MMbbl)

33.2 

Total proved reserves (Bcfe)

1,867.6 

Proved developed reserves (Bcfe)

1,147.4 


Questar E&P’s reserve statistics for the years ended December 31, 2005 through 2007, are summarized below:



Year


Year End Reserves (Bcfe)

Proved Gas and Oil Reserves

Annual Production (Bcfe)


Reserve Life (Years)

2005

1,480.4 

114.2 

13.0 

2006

1,631.4 

129.6 

12.6 

2007

1,867.6 

140.2 

13.3 


In 2007, gas and oil reserves increased 14% to 1,867.6 Bcfe versus a 10% increase in 2006 to 1,631.4 Bcfe.


Questar E&P proved reserves by major operating areas at December 31, 2007 and 2006 follow:


 

2007

2006

 

(Bcfe)

(% of total)

(Bcfe)

(% of total)

Pinedale Anticline

1,033.9 

55%

931.9 

57%

Uinta Basin

301.2 

16%

248.3 

15%

Rockies Legacy

158.6 

9%

142.3 

9%

  Rocky Mountains Total

1,493.7 

80%

1,322.5 

81%

Midcontinent

373.9 

20%

308.9 

19%

  Questar E&P Total

1,867.6 

100%

1,631.4 

100%


Reserves – Cost-of-Service

The following table sets forth estimated cost-of-service proved natural gas reserves, which Wexpro develops and produces for Questar Gas under the terms of the Wexpro Agreement; and Wexpro proved oil reserves. The estimates of cost-of-service proved reserves were made by Wexpro reservoir engineers as of December 31, 2007. All reported reserves are located in the United States.





QUESTAR MARKET RESOURCES 2007 FORM 10-K

14





Estimated cost-of-service proved reserves

 

  Natural gas (Bcf)

615.9 

  Oil (MMbbl)

4.3 

Total proved reserves (Bcfe)

641.9 

Proved developed reserves (Bcfe)

456.9 


The gas reserves operated by Wexpro are delivered to Questar Gas at cost of service. Income from oil properties remaining after recovery of expenses and Wexpro contractual return on investment under the Wexpro Agreement is divided between Wexpro and Questar Gas. Therefore, SEC guidelines with respect to standard economic assumptions are not applicable. The SEC anticipated such potential difficulty and provides that companies may give appropriate recognition to differences arising because of the effect of the ratemaking process. Accordingly, Wexpro reservoir engineers used a minimum producing rate or maximum well-life limit to determine the ultimate quantity of reserves attributable to each well.


Refer to Note 15 of the consolidated financial statements included in Item 8 of Part II of this Annual Report for additional information pertaining to both Questar E&P proved reserves and the Company’s cost-of-service reserves as of the end of each of the last three years.


In addition, to this filing, Questar E&P and Wexpro will each file estimated reserves estimates as of December 31, 2007, with the Energy Information Administration of the Department of Energy on Form EIA-23. Although the companies use the same technical and economic assumptions when they prepare the EIA-23, they are obligated to report reserves for all wells they operate, not for all wells in which they have an interest, and to include the reserves attributable to other owners in such wells.


Production

The following table sets forth the net production volumes, the average sales prices per Mcf of natural gas, per bbl of oil and NGL produced, and the lifting cost per Mcfe for the years ended December 31, 2007, 2006 and 2005. Lifting costs include labor, repairs, maintenance, materials, supplies and workovers, administrative costs of production offices, insurance and property and severance taxes.


 

Year Ended December 31,

 

2007

2006

2005

Questar E&P

 

 

 

Volumes produced and sold

 

 

 

  Natural gas (Bcf)

121.9 

113.9 

100.0 

  Oil and NGL (MMbbl)

3.0 

2.6 

2.4 

    Total production (Bcfe)

140.2 

129.6 

114.2 

Average realized price (including hedges)

 

 

 

  Natural gas (Bcf)

$6.46 

$6.00 

$5.18 

  Oil and NGL (MMbbl)

53.99 

49.12 

41.54 

Lifting costs (per Mcfe)

 

 

 

  Lease operating expense

$ 0.63 

$  0.57 

$  0.54 

  Production taxes

0.43 

0.45 

0.60 

    Total lifting costs

$ 1.06 

$ 1.02 

$ 1.14 

Cost-of-Service

 

 

 

Volumes produced

 

 

 

  Natural gas (Bcf)

34.9 

38.8 

40.0 

  Oil and NGL (MMbbl)

0.4 

0.4 

0.4 


Productive Wells

The following table summarizes the Company’s productive wells (including cost-of-service wells) as of December 31, 2007. All of these wells are located in the United States.




QUESTAR MARKET RESOURCES 2007 FORM 10-K

15



 

Gas

Oil

Total

Gross

5,050 

1,011 

6,061 

Net

2,269 

482 

2,751 


Although many wells produce both gas and oil, a well is categorized as either a gas or an oil well based upon the ratio of gas to oil produced. Each gross well completed in more than one producing zone is counted as a single well. At the end of 2007, there were 140 gross wells with multiple completions.


The Company also holds numerous overriding-royalty interests in gas and oil wells, a portion of which 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 the gross and net-well count.


Leasehold Acres

The following table summarizes developed and undeveloped-leasehold acreage in which the Company owns a working interest as of December 31, 2007. “Undeveloped Acreage” includes leasehold interests that already may have been classified as containing proved undeveloped reserves; and unleased mineral-interest acreage owned by the company. Excluded from the table is acreage in which the Company’s interest is limited to royalty, overriding-royalty and other similar interests. All leasehold acres are located in the U.S.


 

Developed(1)

Undeveloped(2)

Total

 

Gross

Net

Gross

Net

Gross

Net

 

(in acres)

Arizona

 

 

480 

450 

480 

450 

Arkansas

32,721 

10,362 

3,111 

2,207 

35,832 

12,569 

California

314 

26 

1,003 

168 

1,317 

194 

Colorado

149,853 

102,945 

167,337 

79,421 

317,190 

182,366 

Idaho

 

 

44,175 

10,643 

44,175 

10,643 

Illinois

311 

132 

14,207 

3,949 

14,518 

4,081 

Indiana

 

 

1,621 

467 

1,621 

467 

Kansas

29,822 

12,922 

16,880 

3,843 

46,702 

16,765 

Kentucky

 

 

17,323 

6,669 

17,323 

6,669 

Louisiana

15,266 

13,043 

4,491 

4,189 

19,757 

17,232 

Michigan

89 

6,240 

1,262 

6,329 

1,270 

Minnesota

 

 

313 

104 

313 

104 

Mississippi

2,904 

1,799 

965 

398 

3,869 

2,197 

Montana

20,149 

8,138 

306,139 

52,852 

326,288 

60,990 

Nevada

320 

280 

680 

543 

1,000 

823 

New Mexico

98,750 

73,163 

32,939 

12,618 

131,689 

85,781 

North Dakota

4,741 

543 

146,680 

21,774 

151,421 

22,317 

Ohio

 

 

202 

43 

202 

43 

Oklahoma

1,554,755 

280,627 

142,701 

87,830 

1,697,456 

368,457 

Oregon

 

 

43,869 

7,671 

43,869 

7,671 

South Dakota

 

 

204,398 

107,829 

204,398 

107,829 

Texas

151,497 

61,773 

73,219 

56,520 

224,716 

118,293 

Utah

125,265 

96,509 

237,281 

134,772 

362,546 

231,281 

Washington

 

 

26,631 

10,149 

26,631 

10,149 

West Virginia

969 

115 

 

 

969 

115 




QUESTAR MARKET RESOURCES 2007 FORM 10-K

16





Wyoming

258,441 

170,891 

343,421 

232,325 

601,862 

403,216 

  Total

2,446,167 

833,276 

1,836,306 

838,696 

4,282,473 

1,671,972 


(1)Developed acreage is acreage assigned to productive wells.


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


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


Leaseholds Expiring

Acres Expiring

 

Gross

Net

12 months ending December 31,

(in acres)

2008

82,670 

55,138 

2009

73,608 

47,129 

2010

70,067 

37,448 

2011

31,612 

26,682 

2012 and later

187,438 

174,229 


Drilling Activity

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


 

Year Ended December 31,

 

Productive

Dry

 

2007

2006

2005

2007

2006

2005

Net Wells Completed

 

 

 

 

 

 

Exploratory

0.3 

0.9 

6.1 

0.4 

5.2 

1.5 

Development

199.6 

185.6 

165.2 

2.5 

4.6 

7.4 

 

 

 

 

 

 

 

Gross Wells Completed

 

 

 

 

 

 

Exploratory

11 

Development

426 

408 

370 

11 

18 

15 


Midstream Field Services – Questar Gas Management


Gas Management owns 1,550 miles of gathering lines in Utah, Wyoming, and Colorado. Rendezvous Pipeline owns a 21-mile 20-inch-diameter line between Gas Management’s Blacks Fork gas-processing plant and Kern River Gas Transmission Co.’s Muddy Creek compressor station that can deliver up to 300 MMcf of natural gas per day to markets in California and Nevada served by the Kern River pipeline. In conjunction with these gathering facilities, Gas Management owns compression facilities, field-dehydration and measuring systems. Rendezvous owns an additional 229 miles of gathering lines and associated field equipment, Uintah Basin Field Services owns 73 miles of gathering lines and associated field equipment and Three Rivers owns 40 miles of gathering lines. Gas Management owns processing plants that have an aggregate capacity of 474 MMcf of unprocessed natural gas per day.




QUESTAR MARKET RESOURCES 2007 FORM 10-K

17



Energy Marketing – Questar Energy Trading


Energy Trading, through its wholly-owned subsidiary Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir in southwestern Wyoming.


ITEM 3.  LEGAL PROCEEDINGS.


Market Resources is involved in various commercial and regulatory claims and litigation and other legal proceedings that arise in the ordinary course of its business. Management does not believe any of them will have a material adverse effect on the Company’s financial position, results of operations or cash flows. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. Disclosures are provided for contingencies reasonably likely to occur which would have a material adverse effect on the Company’s financial position, results of operations or cash flows. Some of the claims involve highly complex issues relating to liability, damages and other matters subject to substantial uncertainties and, therefore, the probability of liability or an estimate of loss cannot be reasonably determined.


Grynberg Case

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


Environmental Claims

In 2004, the Environmental Protection Agency (EPA) issued two separate compliance orders alleging that Gas Management did not comply with regulatory requirements adopted to implement the federal Clean Air Act. Both orders involved facilities in the Uinta Basin of eastern Utah that were purchased by Questar E&P in mid-2001. The EPA contends such facilities are located within “Indian Country” and are subject to Federal Clean Air Act requirements, rather than air quality rules adopted by the state of Utah. Generally, EPA contends that Gas Management failed to obtain necessary pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations, in violation of federal requirements. Gas Management has generally contested EPA’s allegations, and believes that the permitting and regulatory requirements at issue can be legally avoided under Utah law. EPA has broadened its allegations to include additional potential ongoing violations of the Clean Air Act for the referenced facilities. Other Gas Management facilities in the Uinta Basin have been added to the civil penalty discussions with the EPA, with similar allegations of Clean Air Act violations. These potential violations will likely result in civil penalties of an unknown and undetermined amount in excess of $100,000. The parties are engaged in settlement discussions and have signed a tolling agreement to extend the statute of limitations for filing any claims.


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.





QUESTAR MARKET RESOURCES 2007 FORM 10-K

18


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 18% in 2007 compared to 2006 and 38% in 2006 over 2005. Primary due to higher realized natural gas, crude oil and NGL prices, increased gas-gathering volumes driven by an increase in third-party volumes at Gas Management and an increased investment base at Wexpro.


Following is a comparison of net income by lines of business:


 

Year Ended December 31,

Change

Change

 

2007

2006

2005

2007 vs. 2006

2006 vs. 2005

 

(in millions, except per-share amounts)

Exploration and Production

 

 

 

 

 

    Questar E&P

$285.5 

$253.9 

$172.8 

$31.6 

$ 81.1 

    Wexpro

59.2 

50.0 

43.7 

9.2 

6.3 

Midstream Field Services – Gas Management

55.3 

42.6 

35.7 

12.7 

6.9 

Energy Marketing – Energy Trading and other

20.8 

9.6 

6.0 

11.2 

3.6 

    Net income

$420.8 

$356.1 

$258.2 

$64.7 

$97.9 


RESULTS OF OPERATIONS


Exploration and Production


Questar E&P

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


 

Year Ended December 31,

 

2007

2006

2005

 

(in millions)

Operating Income

 

 

 

Revenues

 

 

 

  Natural gas sales

$   788.2 

$  684.0 

$  517.6 

  Oil and NGL sales

164.2 

128.6 

98.6 

  Other

3.6 

3.1 

4.4 

    Total revenues

956.0 

815.7 

620.6 

Operating expenses

 

 

 

  Operating and maintenance

87.9 

73.6 

61.8 

  General and administrative

56.3 

42.4 

33.9 

  Production and other taxes

60.1 

58.3 

68.7 

  Depreciation, depletion and amortization

243.5 

185.7 

134.7 

  Exploration

22.0 

34.4 

11.1 

  Abandonment and impairment

10.8 

7.6 

7.7 




QUESTAR MARKET RESOURCES 2007 FORM 10-K

19





  Natural gas purchases

2.2 

2.8 

4.2 

    Total operating expenses

482.8 

404.8 

322.1 

et gain (loss) from asset sales

(0.6)

24.3 

1.1 

    Operating income

$  472.6 

$  435.2 

$  299.6 

 

 

Operating Statistics

 

 

 

Questar E&P production volumes

 

 

 

  Natural gas (Bcf)

121.9 

113.9 

100.0 

  Oil and NGL (MMbbl)

3.0 

2.6 

2.4 

    Total production (Bcfe)

140.2 

129.6 

114.2 

  Average daily production (MMcfe)

384.1 

355.2 

312.9 

Questar E&P average realized price, net to the well (including hedges)

 

 

 

  Natural gas (per Mcf)

$6.46 

$6.00 

$5.18 

  Oil and NGL (per bbl)

$53.99 

$49.12 

$41.54 


Questar E&P reported net income of $285.5 million in 2007, up 12% from $253.9 million in 2006 and $172.8 million in 2005. The impact of higher realized prices for natural gas, crude oil, and NGL was partially offset by a higher average production cost structure.


Questar E&P production volumes were 140.2 Bcfe in 2007, compared to 129.6 Bcfe in the year-earlier period. On an energy-equivalent basis, natural gas comprised approximately 87% of Questar E&P 2007 production. A comparison of natural gas-equivalent production by major operating area is shown in the following table:


 

Year Ended December 31,

Change

Change

 

2007

2006

2005

2007 vs. 2006

2006 vs. 2005

 

(in Bcfe)

Pinedale Anticline

47.4 

39.5 

33.2 

7.9 

6.3 

Uinta Basin

25.4 

25.1 

25.6 

0.3 

(0.5)

Rockies Legacy

16.4 

18.3 

16.7 

(1.9)

1.6 

  Rocky Mountain total(a)

89.2 

82.9 

75.5 

6.3 

7.4 

Midcontinent

51.0 

46.7 

38.7 

4.3 

8.0 

    Total Questar E&P

140.2 

129.6 

114.2 

10.6 

15.4 


(a)Questar E&P shut in approximately 10.3 Bcfe (net) of production in 2007 and 1.2 Bcfe (net) of production in 2006 in the Rocky Mountain region in response to low natural gas prices.


Questar E&P production from the Pinedale Anticline in western Wyoming grew 20% to 47.4 Bcfe in 2007 as a result of ongoing development drilling. Pinedale production growth is influenced by seasonal access restrictions imposed by the Bureau of Land Management that limit the company’s ability to drill and complete wells during the mid-November to early-May period.


Questar E&P Rockies Legacy properties include all of the company’s Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin. Rockies Legacy 2007 production of 16.4 Bcfe was 1.9 Bcfe lower than a year ago.


In the Midcontinent, Questar E&P grew production 9% to 51.0 Bcfe in 2007, driven by ongoing infill-development drilling in Elm Grove field in northwestern Louisiana. Net production from Elm Grove field increased to 16.4 Bcfe in 2007 compared to 14.3 Bcfe in the year-earlier period.


Questar E&P also benefited from higher realized prices for natural gas, oil and NGL. The weighted-average realized natural gas price for Questar E&P (including the impact of hedging) was $6.46 per Mcf compared to $6.00 per Mcf for the same period in




QUESTAR MARKET RESOURCES 2007 FORM 10-K

20


2006, an 8% increase. Realized oil and NGL prices in 2007 averaged $53.99 per bbl, compared with $49.12 per bbl during the prior-year period, a 10% increase. A regional comparison of average realized prices, including hedges, is shown in the following table:


 

Year Ended December 31,

Change

Change

 

2007

2006

2005

2007 vs. 2006

2006 vs. 2005

Natural gas (per Mcf)

 

 

 

 

 

  Rocky Mountains

$5.92 

$5.73 

$5.01 

$0.19 

$0.72 

  Midcontinent

7.42 

6.47 

5.49 

0.95 

0.98 

    Volume-weighted average

6.46 

6.00 

5.18 

0.46 

0.82 

Oil and NGL (per bbl)

 

 

 

 

 

  Rocky Mountains

$53.51 

$46.62 

$42.08 

$6.89 

$4.54 

  Midcontinent

54.85 

54.93 

40.25 

(0.08)

14.68 

    Volume-weighted average

53.99 

49.12 

41.54 

4.87 

7.58 


Questar E&P hedged or pre-sold approximately 75% of gas production in 2007, and hedged or pre-sold 70% of gas production in the comparable 2006 period. Hedging increased Questar E&P gas revenues by $245.7 million in 2007 and $53.7 million in 2006. The company hedged or pre-sold approximately 61% of its oil production in 2007, and hedged or pre-sold 78% of its oil production in the same period of 2006. Oil hedges reduced revenues $17.2 million in 2007 and $19.6 million in 2006.


Questar may hedge up to 100% of forecasted production from proved reserves to lock in acceptable returns on invested capital and to protect returns, cash flow and net income from a decline in commodity prices. During 2007, Questar E&P hedged additional production through 2010. In the second quarter of 2006, the company began using basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials that may result from capacity constraints on regional gas pipelines. Net mark-to-market changes in natural gas basis-only swaps increased 2007 net income by $3.6 million compared to a $1.2 million reduction in the prior-year period. Derivative positions as of December 31, 2007, are summarized in Item 7A of Part II in this annual report.


Questar E&P production costs (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense, allocated-interest expense and production taxes) per Mcfe of production increased 13% to $3.38 per Mcfe in 2007 compared to $2.99 per Mcfe in 2006. Questar E&P production costs are summarized in the following table:


 

Year Ended December 31,

Change

Change

 

2007

2006

2005

2007 vs. 2006

2006 vs. 2005

 

(per Mcfe)

Depreciation, depletion and amortization

$1.74 

$1.43 

$1.18 

$0.31 

$0.25 

Lease operating expense

0.63 

0.57 

0.54 

0.06 

0.03 

General and administrative expense

0.40 

0.33 

0.30 

0.07 

0.03 

Allocated-interest expense

0.18 

0.21 

0.21 

(0.03)

 

Production taxes

0.43 

0.45 

0.60 

(0.02)

(0.15)

  Total production costs

$3.38 

$2.99 

$2.83 

$0.39 

$0.16 


Production volume-weighted average depreciation, depletion and amortization expense per Mcfe increased in 2007 due to higher costs for drilling, completion and related services, higher cost of steel casing, other tubulars and wellhead equipment, the ongoing depletion of older, lower-cost reserves and the increasing component of Questar E&P production derived from higher-cost fields such as Elm Grove in the Midcontinent and Vermillion Basin in the Rockies. Lease operating expense per Mcfe increased due to higher costs of materials and consumables, increased produced-water disposal costs and higher well-workover activity. General and administrative expense per Mcfe grew due to increased labor and legal expenses in 2007. Allocated-interest expense per unit of production decreased in 2007 due to reduced debt expense and increased 2007 production. Production taxes were lower in 2007 due to lower market prices for natural gas. The company pays production taxes per Mcfe based on sales pric es before the impact of hedges.




QUESTAR MARKET RESOURCES 2007 FORM 10-K

21



Questar E&P exploration expense decreased $12.4 million or 36% in 2007 compared to 2006. In 2006, Questar E&P recorded a $10.0 million charge related to the abandoned deep exploratory portion of the Stewart Point 15-29 well on the Pinedale Anticline after failing to establish commercial production in the Hilliard and Rock Springs formations.


In 2006, Questar E&P sold certain proved reserves and undeveloped leasehold interests in western Colorado and recognized a pre-tax gain of $22.7 million.


Questar E&P major operating areas are discussed below.


Pinedale Anticline: As of December 31, 2007, Market Resources (including both Questar E&P and Wexpro) operated and had working interests in 250 producing wells on the Pinedale Anticline compared to 195 a year earlier. Of the 250 producing wells, Questar E&P has working interests in 228 wells, overriding royalty interests in an additional 21 Wexpro-operated wells, and no interest in one well operated by Wexpro. Wexpro has working interests in 71 of the 250 producing wells.


In 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10-acre-density drilling for Lance Pool wells on about 12,700 (gross) acres of Market Resources 18,208 acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the currently estimated productive limits of Market Resources core acreage in the field. At December 31, 2007, Questar E&P had booked 355 proved undeveloped locations on a combination of 10- and 20-acre density and reported estimated net proved reserves at Pinedale of 1,033.9 Bcfe, or 55% of Questar E&P’s total proved reserves. The company is evaluating the economic potential of development on five-acre density at Pinedale. In January 2008, the WOGCC approved five-acre-density drilling for Lance Pool wells on about 4,200 gross acres of Market Resources Pinedale leasehold. If five-acre-density development is appropriate for a majority of its leasehold, the company currently estimates up to an additional 1,600 wells will be required to fully develop the Lance Pool on its acreage.


Uinta Basin: As of December 31, 2007, Questar E&P had a working interest in 857 producing wells in the Uinta Basin of eastern Utah, compared to 811 at December 31, 2006. At December 31, 2007, Questar E&P had booked 123 proved-undeveloped locations and reported estimated net proved reserves in the Uinta Basin of 301.2 Bcfe or 16% of Questar E&P’s total proved reserves. Uinta Basin proved reserves are found in a series of vertically-stacked, laterally discontinuous reservoirs at depths of 5,000 feet to deeper than 16,000 feet. Questar E&P owns interests in over 242,000 gross leasehold acres in the Uinta Basin.


Rockies Legacy: The remainder of Questar E&P Rocky Mountain region leasehold interests, productive wells and proved reserves are distributed over a number of basins, fields and properties managed as the company’s Rockies Legacy division. Most of the properties are located in the Greater Green River Basin of western Wyoming. In aggregate, Rockies Legacy properties comprised 158.6 Bcfe or 9% of Questar E&P total proved reserves at December 31, 2007. Within the division, exploratory and development activity is planned for 2008 within the San Juan, Paradox, Powder River, Green River and Vermillion basins.


In the Vermillion Basin on the southwestern Wyoming-northwestern Colorado state line, Market Resources companies continue to evaluate the potential of several formations under 146,000 net leasehold acres. As of December 31, 2007, Market Resources had recompleted two older wells and drilled and completed 20 new wells. The targets are the Baxter Shale, a thick, overpressured shale found at depths of about 9,500 to about 13,000 feet and deeper Frontier and Dakota tight-sand formations at depths to about 14,000 feet.


Midcontinent: Questar E&P Midcontinent properties are distributed over a large area, including the Anadarko basin of Oklahoma and the Texas Panhandle, the Arkoma basin of Oklahoma and western Arkansas, and the Ark-La-Tex region of Louisiana, Texas and Arkansas. With the exception of the Elm Grove field in northwest Louisiana and the Granite Wash play in the Texas Panhandle, Questar E&P Midcontinent leasehold interests are highly fragmented, with no significant concentration of property interests. Questar E&P reported Midcontinent proved reserves of 373.9 Bcfe on December 31, 2007, 20% of Questar E&P’s total year-end proved reserves at December 31, 2007.


Questar E&P continues a two-rig infill-development project on its largest single Midcontinent asset, the Elm Grove field in northwest Louisiana. As of December 31, 2007, Questar E&P operated or had working interests in 293 producing wells in the Elm Grove field compared to 231 at December 31, 2006. At December 31, 2007, Questar E&P had 38 proved-undeveloped locations and reported estimated net proved reserves at Elm Grove of 104.6 Bcfe, or 6% of the company’s total proved reserves.





QUESTAR MARKET RESOURCES 2007 FORM 10-K

22


Wexpro

Wexpro reported net income of $59.2 million in 2007 compared to $50.0 million in 2006, an 18% increase. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19% to 20% on its investment in commercial wells and related facilities – adjusted for working capital and reduced for deferred income taxes and depreciation (investment base). Wexpro investment base at December 31, 2007, was $300.4 million, an increase of $39.8 million or 15% from December 31, 2006. Wexpro produced 34.9 Bcf of cost-of-service gas in 2007.


Midstream Field Services – Questar Gas Management


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


 

Year Ended December 31,

 

2007

2006

2005

 

(in millions)

Operating Income

 

 

 

Revenues

 

 

 

  Gathering

$111.4 

$  89.2 

  $74.5 

  Processing

94.9 

94.7 

80.7 

    Total revenues

206.3 

183.9 

155.2 

Operating expenses

 

 

 

  Operating and maintenance

83.6 

92.4 

85.2 

  General and administrative

17.2 

12.2 

7.5 

  Production and other taxes

1.4 

0.6 

0.7 

  Depreciation, depletion and amortization

19.1 

15.3 

11.3 

  Abandonment and impairments

0.4 

 

 

    Total operating expenses

121.7 

120.5 

104.7 

Net gain from asset sales

 

1.0 

 

    Operating income

$  84.6 

$  64.4 

$  50.5 

 

 

Operating Statistics

 

 

 

Natural gas processing volumes

 

 

 

  NGL sales (MMgal)

76.5 

88.1 

88.4 

  NGL sales price (per gal)

$0.98 

$0.88 

$0.77 

  Fee-based processing volumes (in millions of MMBtu)

 

 

 

    For unaffiliated customers

44.1 

37.5 

13.2 

    For affiliated customers

82.5 

82.9 

62.3 

      Total fee-based processing volumes

126.6 

120.4 

75.5 

  Fee-based processing (per MMBtu)

$0.15 

$0.14 

$0.15 

Natural gas gathering volumes (in millions of MMBtu)

 

 

 

  For unaffiliated customers

162.1 

124.1 

112.6 

  For affiliated customers

128.1 

150.0 

144.4 

    Total gas gathering volumes

290.2 

274.1 

257.0 

  Gas gathering revenue (per MMBtu)

$0.32 

$0.29 

$0.25 


Gas Management grew net income to $55.3 million in 2007 compared to $42.6 million in the 2006 period, a 30% increase driven by higher gathering and processing volumes.





QUESTAR MARKET RESOURCES 2007 FORM 10-K

23


Gathering volumes increased 16.1 million MMBtu, or 6% to 290.2 million MMBtu in 2007. New projects serving third parties in the Uinta Basin and expanded Pinedale production contributed to a 31% increase in third-party volumes during 2007. Total gathering margins (revenues minus direct expenses) during 2007 increased 35% to $67.1 million compared to $49.6 million in 2006.


Fee-based gas-processing volumes were 126.6 million MMBtu in 2007, a 5% increase compared to the 2006 period. Fee-based gas-processing revenues increased 14% or $2.2 million, while gross margin from keep-whole processing increased 40% or $12.9 million in 2007. Approximately 74% of Gas Management net operating revenue (total revenue less processing plant-shrink) is derived from fee-based contracts, compared to 77% in 2006. Gas Management uses forward sales contracts to reduce margin volatility associated with keep-whole contracts. Forward sales contracts reduced NGL revenues by $5.8 million in 2007 and increased revenues by $0.7 million in 2006.


Energy Marketing – Questar Energy Trading

Energy Trading grew net income 117% to $20.8 million in 2007 compared to $9.6 million in 2006, driven primarily by increased trading margins. Gross marketing margin (gross revenues less costs for gas and oil purchases, transportation and gas storage) totaled $31.6 million in 2007 compared to $16.0 million a year ago. The increase in trading margin was due primarily to increased storage activity over the same period last year. Energy Trading reported unaffiliated revenues of $504.4 million in 2007 compared with $656.0 million in 2006, a 23% decrease primarily resulting from lower regional-market prices for natural gas. The weighted-average natural gas sales price decreased 20% in 2007 to $4.29 per MMBtu, compared to $5.34 per MMBtu for the 2006 period.


Consolidated Results Before Net Income


Net gain (loss) from asset sales

During 2006, Questar E&P sold certain proved reserves and undeveloped leasehold interests in western Colorado and recognized a pre-tax gain of $22.7 million. The gain is included in the Consolidated Statement of Income line item “Net gain (loss) from asset sales”.


Income from unconsolidated affiliates

Income from unconsolidated affiliates, primarily Rendezvous Gas Services, was $8.9 million in 2007 compared to $7.5 million in 2006. Rendezvous Gas Services provides gas-gathering services for the Pinedale and Jonah producing areas. Rendezvous gathering volumes increased 20% in 2007 compared to 2006 and 1% in 2006 compared to 2005.


Interest expense and loss on early extinguishment of debt

Interest expense was 5% higher in 2007 compared to 2006 as a result of higher interest rates and increased borrowings. Interest expense rose in 2006 compared to 2005 due primarily to increased average debt levels and higher interest rates on short term debt outstanding in the early part of 2006. Market Resources recognized a $1.7 million pre-tax loss in 2006 on the early extinguishment of its 7% Notes due 2007.


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

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


Investing Activities

Capital spending in 2007 amounted $943.9 million. The details of capital expenditures in 2007 and 2006 and a forecast for 2008 are shown in the table below:


 

Year Ended December 31,

 

2008

Forecast

2007

2006

 

(in millions)

Drilling and other exploration

$   76.7 

$   32.7 

$  13.6 

Dry exploratory well expenses

 

12.3 

26.3 

Development drilling

779.4 

612.0 

532.6 

Wexpro development drilling

125.7 

97.2 

76.8 




QUESTAR MARKET RESOURCES 2007 FORM 10-K

24





Reserve acquisitions

643.9 

44.8 

29.3 

Production

18.7 

28.2 

22.7 

Midstream field services

389.1 

125.7 

80.4 

Storage

0.2 

0.3 

1.1 

General

7.8 

11.1 

5.6 

Capital expenditure accruals

 

(20.4)

(35.7)

  Total

$2,041.5 

$943.9 

$752.7 


In 2007 and 2006, Market Resources increased drilling activity at Pinedale and in the Midcontinent region. During 2007, Market Resources participated in 607 wells (202.8 net), resulting in 199.9 net successful gas and oil wells and 2.9 net dry or abandoned wells. The 2007 net drilling-success rate was 98.6%. There were 167 gross wells in progress at year-end. Market Resources also increased investment in its midstream gathering and processing-services business to expand capacity in both western Wyoming and eastern Utah in response to growing equity and third-party production volumes. On January 31, 2008, Questar E&P entered into agreements with multiple private sellers to acquire two significant natural gas development properties in northwest Louisiana for an aggregate purchase price of $655 million. In February 2008, Market Resources established a $700 million term-loan credit facility to finance the purchase of the Louisiana natural gas development properties. Market Resources pla ns to expand its current revolving credit facility to $800 million and issue up to $500 million of additional long-term debt to retire the $700 million term loan credit facility.


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, 2007:


 

Payments Due by Year

 

Total

2008

2009

2010

2011

2012

After 2012

 

(in millions)

Long-term debt

$500.0 

 

 

 

$150.0 

$100.0 

$250.0 

Interest on fixed-rate long-term debt

166.7 

$26.4 

$26.4 

$26.4 

17.0 

15.1 

55.4 

Transportation contracts

55.5 

8.7 

7.9 

7.6 

7.3 

5.3 

18.7 

Operating leases

16.4 

3.6 

3.6 

3.3 

2.8 

1.8 

1.3 

  Total

$738.6 

$38.7 

$37.9 

$37.3 

$177.1 

$122.2 

$325.4 


The Company had $100 million of variable-rate long-term debt outstanding due 2012 with an interest rate of 5.55% at December 31, 2007.


Critical Accounting Policies, Estimates and Assumptions

Market Resources’ significant accounting policies are described in Note 1 to the consolidated financial statements included in Item 8 of Part II of this Annual Report. The Company’s consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles. The preparation of consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. The following accounting policies may involve a higher degree of complexity and judgment on the part of management.


Gas and Oil Reserves

Gas and oil reserve estimates require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, production history, and economic assumptions relating to commodity prices, production costs, severance and other taxes, capital expenditures and remediation costs. The subjective judgments and variances in data for various fields make these estimates less precise than other estimates included in the financial statement disclosures. For 2007, revisions of reserve estimates, other than revisions related to Pinedale increased-density, resulted in a 46.2 Bcfe increase in Questar E&P’s proved reserves and a 30.0 Bcfe decrease in cost-of-service proved reserves. Revisions associated with Pinedale increased-density drilling added 126.8 Bcfe to Questar E&P’s estimated prove d reserves at December 31, 2007, and 25.9 Bcfe of additional cost-of-service proved reserves. See Note 15 for more information on the Company’s estimated proved reserves.




QUESTAR MARKET RESOURCES 2007 FORM 10-K

25



Successful Efforts Accounting for Gas and Oil Operations

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


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


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


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


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


Accounting for Derivatives Contracts

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


Revenue Recognition

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


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




QUESTAR MARKET RESOURCES 2007 FORM 10-K

26


Commodity-Price Risk Management


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


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


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


Market Resources enters into commodity-price derivative arrangements that do not require collateral deposits. Counterparties include banks and energy-trading firms with investment-grade credit ratings. The amount of credit available may vary depending on the credit ratings assigned to Market Resources debt. In addition to the counterparty arrangements, Market Resources has a $182.0 million long-term revolving-credit facility with banks with $100 million borrowed at December 31, 2007.


Generally, derivative instruments are matched to equity gas and oil production, thus qualifying as cash-flow hedges under the accounting provisions of SFAS 133 as amended and interpreted. Changes in the fair value of cash-flow hedges are recorded on the balance sheet and in accumulated other comprehensive income (loss) until the underlying gas or oil is produced. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. The ineffective portion of cash-flow hedges is immediately recognized in the determination of net income.


Market Resources began using natural gas basis-only swaps in 2006 to manage the risk of a widening of basis differentials in the Rocky Mountains. These contracts are marked-to-market with any change in the valuation recognized in the determination of net income.


A summary of Market Resources derivative positions for equity production as of December 31, 2007, is shown below:


 

 

Rocky

 

 

 

Rocky

 

 

Time Periods

Mountains

Midcontinent

Total

 

Mountains

Midcontinent

Total

 

 

 

 

 

 

Estimated

 

 

Gas (Bcf) Fixed-price Swaps

 

Average price per Mcf, net to the well

2008

 

 

 

 

 

 

 

 

First half

33.0 

17.3 

50.3 

 

$6.95 

$7.93 

$7.29 

Second half

33.4 

17.4 

50.8 

 

6.97 

7.93 

7.30 

12 months

66.4 

34.7 

101.1 

 

6.96 

7.93 

7.30 

 

 

 

 

 

 

 

 

 




QUESTAR MARKET RESOURCES 2007 FORM 10-K

27



2009

 

 

 

 

 

 

 

 

First half

23.5 

12.0 

35.5 

 

$7.02 

$7.66 

$7.24 

Second half

23.9 

12.2 

36.1 

 

7.02 

7.66 

7.24 

12 months

47.4 

24.2 

71.6 

 

7.02 

7.66 

7.24 

 

 

 

 

 

 

 

 

 

2010

 

 

 

 

 

 

 

 

First half

3.3 

6.9 

10.2 

 

$6.95 

$7.58 

$7.37 

Second half

3.4 

6.9 

10.3 

 

6.95 

7.58 

7.37 

12 months

6.7 

13.8 

20.5 

 

6.95 

7.58 

7.37 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Estimated

 

 

Gas (Bcf) Basis-only Swaps

 

Average basis per Mcf, net to the well

2008

 

 

 

 

 

 

 

 

First half

5.1 

 

5.1 

 

$1.65 

 

$1.65 

Second half

5.1 

 

5.1 

 

1.65 

 

1.65 

12 months

10.2 

 

10.2 

 

1.65 

 

1.65 

 

 

 

 

 

 

 

 

 

2009

 

 

 

 

 

 

 

 

First half

11.8 

1.7 

13.5 

 

$1.21 

$1.08 

$1.19 

Second half

12.0 

1.7 

13.7 

 

1.21 

1.08 

1.19 

12 months

23.8 

3.4 

27.2 

 

1.21 

1.08 

1.19 

 

 

 

 

 

 

 

 

 

2010

 

 

 

 

 

 

 

 

First half

 

1.7 

1.7 

 

 

$0.94 

$0.94 

Second half

 

1.7 

1.7 

 

 

0.94 

0.94 

12 months

 

3.4 

3.4 

 

 

0.94 

0.94 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Estimated

 

 

Oil (Mbbl) Fixed-price Swaps

 

Average price per bbl, net to the well

2008

 

 

 

 

 

 

 

 

First half

419 

218 

637 

 

$67.39 

$70.77 

$68.55 

Second half

423 

221 

644 

 

67.39 

70.77 

68.55 

12 months

842 

439 

1,281 

 

67.39 

70.77 

68.55 

 

 

 

 

 

 

 

 

 

2009

 

 

 

 

 

 

 

 

First half

217 

145 

362 

 

$60.55 

$66.55 

$62.95 

Second half

221 

147 

368 

 

60.55 

66.55 

62.95 

12 months

438 

292 

730 

 

60.55 

66.55 

62.95 


As of December 31, 2007, Market Resources held commodity-price hedging contracts covering about 245.0 million MMBtu of natural gas, 2.0 million barrels of oil, 5.0 million gallons of NGL and basis-only swaps on an additional 40.8 Bcf of natural gas. A




QUESTAR MARKET RESOURCES 2007 FORM 10-K

28


year earlier Market Resources hedging contracts covered 204.2 million MMBtu of natural gas, 1.8 million barrels of oil, 22.7 million gallons of NGL and natural gas basis-only swaps on an additional 47.7 Bcf.


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


 

Fixed-Price

Swaps

Basis-Only Swaps

Total

 

(in millions)

Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2006

$205.6 

($ 1.9)

$203.7 

Contracts realized or otherwise settled 

(153.9)

(1.2)

(155.1)

Change in gas and oil prices on futures markets 

(112.4)

(30.4)

(142.8)

Contracts added

111.8 

36.9 

148.7 

Contracts redesignated as fixed-price swaps

(0.4)

0.4 

 

Net fair value of gas- and oil-derivative contracts outstanding at December 31, 2007

$  50.7 

$ 3.8 

$  54.5 


A table of the net fair value of gas- and oil-derivative contracts as of December 31, 2007, is shown below. About $68.8 million of the fair value of all contracts will settle in the next 12 months and the fair value of cash-flow hedges will be reclassified from other comprehensive income:


 

Fixed-Price

Swaps

Basis-Only Swaps

Total

 

(in millions)

Contracts maturing by December 31, 2008

$70.2 

($ 1.4)

$68.8 

Contracts maturing between January 1, 2009 and December 31, 2009

(13.7)

5.3 

(8.4)

Contracts maturing between January 1, 2010 and December 31, 2010

(5.8)

(0.1)

(5.9)

Net fair value of gas- and oil-derivative contracts

  outstanding at December 31, 2007

$50.7 

$ 3.8 

$54.5 


The following table shows sensitivity of fair value of gas and oil derivative contracts and basis-only swaps to changes in the market price of gas and oil and basis differentials:


 

At December 31,

 

2007

2006

 

(in millions)

Net fair value – asset (liability)

$  54.5 

$203.7 

Value if market prices of gas and oil and basis differentials decline by 10% 

217.7 

334.6 

Value if market prices of gas and oil and basis differentials increase by 10% 

(108.8)

72.8 


Credit Risk

Market Resources requests credit support and, in some cases, prepayment from companies with unacceptable credit risks. Market Resources five largest customers are Sempra Energy Trading Corp., Enterprise Products Operating, Chevron USA Inc., Nevada Power Company, and Occidental Energy Marketing Inc. Sales to these companies accounted for 19% of Market Resources revenues before elimination of intercompany transactions in 2007, and their accounts were current at December 31, 2007.


Interest-Rate Risk

The fair value of fixed-rate debt is subject to change as interest rates fluctuate. The Company had $400.0 million of fixed-rate long-term debt at December 31, 2007 and 2006 with fair values of $403.1 million at December 31, 2007 and $412.8 million at December 31, 2006. If interest rates had declined 10%, fair value would increase to $416.2 million in 2007 and $427.2 million in 2006. The fair value calculations do not represent the cost to retire the debt securities.





QUESTAR MARKET RESOURCES 2007 FORM 10-K

29


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Financial Statements:

Page No.


Report of Independent Registered Public Accounting Firm

31

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

32

Consolidated Balance Sheets at December 31, 2007 and 2006

33

Consolidated Statements of Common Shareholder’s Equity, three years ended

December 31, 2007

34

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

36

Notes Accompanying Consolidated Financial Statements

37

Financial Statement Schedules:

For the three years ended December 31, 2007

    Valuation and Qualifying Accounts

58

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

is shown in the Consolidated Financial Statements or Notes thereto.




QUESTAR MARKET RESOURCES 2007 FORM 10-K

30




Report of Independent Registered Public Accounting Firm


The Board of Directors and Shareholder of

Questar Market Resources


We have audited the accompanying consolidated balance sheets of Questar Market Resources as of December 31, 2007 and 2006, and the related consolidated statements of income, shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 8.  These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.


We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement pr esentation. 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 at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.


As discussed in Note 1 to the financial statements, Questar Market Resources adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes effective January 1, 2007, and Statement of Financial Accounting Standard No. 123R, Share Based Payments, effective January 1, 2006.


/s/ Ernst & Young LLP


Salt Lake City, Utah

February 22, 2008








QUESTAR MARKET RESOURCES 2007 FORM 10-K

31


QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME


 

Year Ended December 31,

 

2007

2006

2005

 

(in millions)

REVENUES

 

 

 

  From unaffiliated customers

$1,671.3 

$1,659.4 

$1,668.7 

  From affiliated companies

172.1 

176.4 

159.5 

    Total Revenues

1,843.4 

1,835.8 

1,828.2 

 

 

 

 

OPERATING EXPENSES

 

 

 

  Cost of natural gas and other products sold (excluding operating

    expenses shown separately)

474.7 

652.6 

888.3 

  Operating and maintenance

187.9 

180.4 

158.6 

  General and administrative

91.3 

69.2 

54.6 

  Production and other taxes

81.6 

89.4 

102.2 

  Depreciation, depletion and amortization

295.1 

235.0 

173.8 

  Exploration

22.0 

34.4 

11.5 

  Abandonment and impairment

11.2 

7.6 

7.9 

  Wexpro Agreement-oil income sharing

4.9 

5.5 

6.1 

    Total Operating Expenses

1,168.7 

1,274.1 

1,403.0 

Net gain (loss) from asset sales

(1.3)

25.2 

0.9 

    OPERATING INCOME

673.4 

586.9 

426.1 

Interest and other income

9.7 

5.8 

5.6 

Income from unconsolidated affiliates

8.9 

7.5 

7.5 

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

5.7 

(1.9)

 

Loss on early extinguishment of debt

 

(1.7)

 

Interest expense

(35.6)

(33.9)

(30.9)

INCOME BEFORE INCOME TAXES

662.1 

562.7 

408.3 

Income taxes

241.3 

206.6 

150.1 

    NET INCOME

$  420.8 

$   356.1 

$  258.2 



See notes accompanying the consolidated financial statements




QUESTAR MARKET RESOURCES 2007 FORM 10-K

32


QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

 

December 31,

 

2007

2006

 

(in millions)

ASSETS

 

 

Current Assets

 

 

  Cash and cash equivalents

 

$   18.2 

  Notes receivable from Questar

$   103.2 

69.8 

  Federal income taxes recoverable

4.6 

1.4 

  Accounts receivable, net

246.1 

235.9 

  Accounts receivable from affiliates

18.3 

21.8 

  Fair value of derivative contracts

78.1 

155.5 

  Inventories, at lower of average cost or market

 

 

    Gas and oil storage

23.2 

27.7 

    Materials and supplies

33.2 

28.7 

  Prepaid expenses and other

18.2 

22.5 

    Total Current Assets

524.9 

581.5 

Property, Plant and Equipment – successful efforts

    method of accounting for gas and oil properties

 

 

  Questar E&P

 

 

    Proved properties

3,306.9 

2,646.6 

    Unproved properties, not being depleted

55.6 

42.7 

    Support equipment and facilities

23.3 

18.5 

  Wexpro

766.1 

658.6 

  Gas Management

516.5 

404.2 

  Energy Trading and other

39.9 

37.9 

 

4,708.3 

3,808.5 

Less accumulated depreciation, depletion and amortization

 

 

  Questar E&P

1,114.3 

901.5 

  Wexpro

331.4 

305.4 

  Gas Management

115.3 

97.3 

  Energy Trading and other

6.7 

5.5 

 

1,567.7 

1,309.7 

    Net Property, Plant and Equipment

3,140.6 

2,498.8 

Investment in unconsolidated affiliates

52.8 

37.5 

Other Assets

 

 

  Goodwill

60.9 

60.9 

  Contract receivable from Questar Gas

3.9 

4.2 

  Fair value of derivative contracts

7.8 

49.0 

  Other noncurrent assets

15.5 

17.7 

    Total Other Assets

88.1 

131.8 

    Total Assets

$3,806.4 

$3,249.6 





QUESTAR MARKET RESOURCES 2007 FORM 10-K

33



LIABILITIES AND SHAREHOLDER’S EQUITY


 

December 31,

 

2007

2006

 

(in millions)

Current Liabilities

 

 

  Notes payable to Questar

$  118.9 

$   142.6 

  Accounts payable and accrued expenses

 

 

    Accounts and other payables

303.7 

295.3 

    Accounts payable to affiliates

13.0 

17.3 

    Production and other taxes

40.9 

53.4 

    Interest

9.3 

8.8 

    Total accounts payable and accrued expenses

366.9 

374.8 

Fair value of derivative contracts

9.3 

0.6 

Deferred income taxes – current

13.3 

41.7 

   Total Current Liabilities

508.4 

559.7 

 

 

 

Long-term debt

499.3 

399.2 

Deferred income taxes

731.4 

579.0 

Asset retirement obligations

145.3 

128.3 

Fair value of derivative contracts

22.1 

0.2 

Other long-term liabilities

39.8 

38.4 

 

 

 

Commitments and Contingencies – Note 8

 

 

 

 

 

COMMON SHAREHOLDER’S EQUITY

 

 

  Common stock – par value $1 per share;

 

 

    25.0 shares authorized; 4.3 shares issued and outstanding

4.3 

4.3 

  Additional paid-in capital

130.9 

122.0 

  Retained earnings

1,693.9 

1,290.4 

  Accumulated other comprehensive income

31.0 

128.1 

    Total Common Shareholder’s Equity

1,860.1 

1,544.8 

 

 

 

    Total Liabilities and Common Shareholder’s Equity

$3,806.4 

$3,249.6 



See notes accompanying the consolidated financial statements




QUESTAR MARKET RESOURCES 2007 FORM 10-K

34


QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY


 

 

 

 

Accumulated

 

 

 

Additional

 

Other

Comprehensive

 

Common

Paid-in

Retained

Comprehensive

Income

 

Stock

Capital

Earnings

Income (Loss)

(Loss)

 

(in millions)

Balance at January 1, 2005

$   4.3 

$116.0 

$   710.7 

($ 42.1)

 

2005 net income

 

 

258.2 

 

$258.2 

Dividends paid

 

 

(17.3)

 

 

Other comprehensive loss

 

 

 

 

 

  Change in unrealized fair value of derivatives

 

 

 

(251.5)

(251.5)

  Income taxes

 

 

 

95.5 

95.5 

  Total comprehensive income

 

 

 

 

$102.2 

Balance at December 31, 2005

4.3 

116.0 

 951.6 

(198.1)

 

2006 net income

 

 

356.1 

 

$356.1 

Dividends paid

 

 

(17.3)

 

 

Share-based compensation

 

6.0 

 

 

 

Other comprehensive income

 

 

 

 

 

  Change in unrealized fair value of derivatives

 

 

 

524.9 

524.9 

  Income taxes

 

 

 

(198.7)

(198.7)

  Total comprehensive income

 

 

 

 

$682.3 

Balance at December 31, 2006

4.3 

122.0 

1,290.4 

128.1 

 

2007 net income

 

 

420.8 

 

$420.8 

Dividends paid

 

 

(17.3)

 

 

Share-based compensation

 

8.9 

 

 

 

Other comprehensive income

 

 

 

 

 

  Change in unrealized fair value of derivatives

 

 

 

(156.1)

(156.1)

  Income taxes

 

 

 

59.0 

59.0 

  Total comprehensive income

 

 

 

 

$323.7 

Balance at December 31, 2007

$   4.3 

$130.9 

$1,693.9 

$  31.0 

 



See notes accompanying the consolidated financial statements




QUESTAR MARKET RESOURCES 2007 FORM 10-K

35


QUESTAR MARKET RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


 

Year Ended December 31,

 

2007

2006

2005

 

(in millions)

OPERATING ACTIVITIES

 

 

 

Net income

$420.8 

$356.1 

$258.2 

Adjustments to reconcile net income to net cash

 

 

 

    provided from operating activities:

 

 

 

  Depreciation, depletion and amortization

296.0 

236.8 

174.9 

  Deferred income taxes

183.0 

110.7 

93.2 

  Abandonment and impairment

11.2 

7.6 

7.9 

  Share-based compensation

8.9 

6.0 

 

  Dry exploration well expenses

12.3 

26.3 

3.1 

  Net (gain) loss from asset sales

1.3 

(25.2)

(0.9)

  Income from unconsolidated affiliates

(8.9)

(7.5)

(7.5)

  Distribution from unconsolidated affiliates

10.4 

7.1 

10.0 

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

(5.7)

1.9 

 

  Loss on early extinguishment of debt

 

1.7 

 

Changes in operating assets and liabilities:

 

 

 

  Accounts receivable

(6.7)

32.7 

(95.3)

  Inventories

5.8 

0.7 

(26.0)

  Prepaid expenses

4.3 

0.9 

(6.7)

  Accounts payable and accrued expenses

(34.0)

(28.0)

121.2 

  Federal income taxes

(3.2)

12.7 

(18.7)

  Other

 

(12.1)

7.0 

  NET CASH PROVIDED FROM OPERATING ACTIVITIES

895.5 

728.4 

520.4 

 

 

 

 

INVESTING ACTIVITIES

 

 

 

Capital expenditures

 

 

 

  Property, plant and equipment

(929.1)

(746.4)

(576.2)

  Other investments

(14.8)

(6.3)

 

    Total capital expenditures

(943.9)

(752.7)

(576.2)

Proceeds from disposition of assets

4.6 

29.0 

1.9 

  NET CASH USED IN INVESTING ACTIVITIES

(939.3)

(723.7)

(574.3)

 

 

 

 

FINANCING ACTIVITIES

 

 

 

Checks in excess of cash balances

 

 

(4.3)

Change in notes receivable from Questar

(33.4)

19.3 

(39.7)

Change in notes payable to Questar

(23.7)

(38.2)

119.6 

Long-term debt issued, net of issue costs

100.0 

247.0 

200.0 

Long-term debt repaid

 

(200.0)

(200.0)

Early extinguishment of debt costs

 

(1.7)

 




QUESTAR MARKET RESOURCES 2007 FORM 10-K

36



Dividends paid

(17.3)

(17.3)

(17.3)

  NET CASH PROVIDED FROM FINANCING ACTIVITIES

25.6 

9.1 

58.3 

Change in cash and cash equivalents

(18.2)

13.8 

4.4 

Beginning cash and cash equivalents

18.2 

4.4 

 

Ending cash and cash equivalents

$        

$   18.2 

$   4.4 

 

 

 

 

Supplemental Disclosure of Cash Paid During the Year for:

 

 

 

  Interest

$34.5 

$31.9 

$30.4 

  Income taxes

64.9 

81.1 

73.8 



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

Questar Market Resources, Inc. (Market Resources or the Company) is a natural gas-focused energy company, a wholly-owned subsidiary of Questar Corporation (Questar) and Questar’s primary growth driver. Market Resources is a subholding company with three major lines of business – gas and oil exploration and production, midstream field services, and energy marketing – which are conducted through its four principal subsidiaries:


·

Questar Exploration and Production Company (Questar E&P) acquires, explores for, develops and produces natural gas, oil, and NGL;

·

Wexpro Company (Wexpro) manages, develops and produces cost-of-service reserves for gas utility affiliate, Questar Gas;

·

Questar Gas Management Company (Gas Management) provides midstream field services including natural gas-gathering and processing services for affiliates and third parties; and

·

Questar Energy Trading Company (Energy Trading) markets equity and third-party gas and oil, provides risk-management services, and owns and operates an underground gas-storage reservoir.


Principles of Consolidation

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


Investment in Unconsolidated Affiliates

Market Resources uses the equity method to account for investment in unconsolidated affiliates where it does not have control, but has significant influence. Generally, the investment in unconsolidated affiliates on the Company’s consolidated balance sheets equals the Company’s proportionate share of equity reported by the unconsolidated affiliates. Investment is assessed for possible impairment when events indicate that the fair value of the investment may be below the Company’s carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down would be included in the determination of net income.


The principal unconsolidated affiliates and Market Resources’ ownership percentage as of December 31, 2007, were Rendezvous Gas Services, LLC, a limited liability corporation (50%), Uintah Basin Field Services, LLC, a limited liability corporation (38%) and Three Rivers Gathering, a limited liability corporation (50%). These entities are engaged in gathering and compressing natural gas.





QUESTAR MARKET RESOURCES 2007 FORM 10-K

37


Use of Estimates

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


Revenue Recognition

Market Resources subsidiaries recognize revenues in the period that services are provided or products are delivered. Revenues reflect the impact of price-hedging instruments. Revenues associated with the production of gas and oil are accounted for using the sales method, whereby revenue is recognized as gas and oil is sold to purchasers. A liability is recorded to the extent that the company has sold volumes in excess of its share of remaining gas and oil reserves in an underlying property. Market Resources imbalance obligations at December 31, 2007 and 2006, were $2.7 million.


Energy Trading reports revenues on a gross basis because, in the judgment of management, the nature and circumstances of its marketing transactions are consistent with guidance for gross revenue reporting. Market Resources is primarily engaged in gas and oil exploration and production and midstream field services. Energy Trading markets equity natural gas, oil and NGL and third-party volumes. Energy Trading uses derivatives to secure a known price for a specific volume over a specific time period. Energy Trading does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. Energy Trading has not engaged in buy/sell arrangements, as described in EITF 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty.”


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 11 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 balances are stated at historical cost. Maintenance and repair costs are expensed as incurred.


Gas and oil properties

Questar E&P uses the successful efforts method to account for gas and oil properties. The costs of acquiring leaseholds, drilling development wells, drilling successful exploratory wells, purchasing related support equipment and facilities are capitalized and depreciated on a field basis using the unit-of-production method and the estimated proved developed gas and oil reserves. Costs of geological and geophysical studies and other exploratory activities are expensed as incurred. Costs of production and general corporate activities are expensed in the period incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected.


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





QUESTAR MARKET RESOURCES 2007 FORM 10-K

38


Capitalized exploratory well costs

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


Cost-of-service gas and oil operations

The successful efforts method of accounting is used for “cost-of-service” gas and oil properties 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 11). 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 on a field-by-field basis using the unit-of-production method and the estimated proved gas and oil reserves. Oil and NGL volumes are converted to natural gas equivalents using the ratio of one barrel of crude oil, condensate or NGL to 6,000 cubic feet of natural gas. Capitalized costs of exploratory wells that have found proved gas and oil reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves on a field basis. The Company capitalizes an estimate of the fair value of future abandonment costs. Future abandonment costs, less estimated future salvage values, are depreciated over the life of the related asset using a unit-of-production method. The following rates per Mcfe represent the volume-weighted average depreciation, depletion and amortization rates of the Company’s capitalized costs for the periods:


 

2007

2006

2005

Gas and oil properties, per Mcfe

$1.74 

$1.43 

$1.18 

Cost-of-service gas and oil properties, per Mcfe

1.09 

$1.04 

0.83 


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


Impairment of Long-Lived Assets

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


Goodwill and Other Intangible Assets

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


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

The Company capitalizes interest costs when applicable. The Wexpro Agreement requires capitalization of AFUDC on cost-of-service construction projects. The FERC requires the capitalization of AFUDC during the construction period of rate-regulated




QUESTAR MARKET RESOURCES 2007 FORM 10-K

39


plant and equipment. AFUDC on equity funds amounted to $1.3 million in 2007, $0.9 million in 2006 and $0.4 million in 2005 and increased interest and other income in the Consolidated Statements of Income.


Derivative Instruments

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


·

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

·

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

·

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


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


Basis-Only Swaps

Basis-only swaps are used to manage the risk of widening basis differentials. These contracts are marked to market monthly with any change in the valuation recognized in the determination of net income.


Physical Contracts

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


Financial Contracts

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


Credit Risk

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


Bad debt expense amounted to $0.1 million in 2007, $1.4 million in 2006 and $0.1 million in 2005. The allowance for bad debt expenses was $3.3 million and $4.3 million at December 31, 2007 and 2006, respectively.





QUESTAR MARKET RESOURCES 2007 FORM 10-K

40


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. Interest earned on refunds is recorded in interest and other income. Interest expense charged on tax deficiencies is recorded in interest expense.


In July 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation 48, “Accounting for Uncertainty in Income Taxes” (FIN 48). The interpretation applies to all tax positions related to income taxes subject to SFAS 109 “Accounting for Income Taxes.” FIN 48 provides guidance for the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Questar adopted the provisions of FIN 48 effective January 1, 2007. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company’s recorded income tax benefits will be fully realized. There were no unrecognized tax benefits at the beginning or at the end of the twelve-month period ended December 31, 2007. Income tax returns for 2004 and subsequent years are subject to examination. As of the date of adoption, there were no amounts accrued for penalties or interest related to unrecognized tax benefits.


Share-Based Compensation

Questar issues stock options and restricted shares to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). Prior to January 1, 2006, the Company accounted for share-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion (APBO) 25 “Accounting for Stock Issued to Employees” and related interpretations. No compensation cost was recorded for stock options issued because the exercise price equaled the market price on the date of grant. The granting of restricted shares resulted in recognition of compensation cost measured at the grant-date market price.


The Company implemented Statement of Financial Accounting Standards 123R “Share Based Payment,” (SFAS 123R) effective January 1, 2006, and chose the modified prospective phase-in method. The modified prospective phase-in method requires recognition of compensation costs for all share-based payments granted, modified or settled after January 1, 2006, as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. Market Resources uses an accelerated method in recognizing share-based compensation costs with graded-vesting 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

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


Recent Accounting Developments


SFAS 157 “Fair Value Measures

The FASB issued SFAS 157 “Fair Value Measures” in September 2006. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measures required by other accounting rules. It does not change existing guidance as to whether or not an instrument is carried at fair value. SFAS 157 will be effective for Questar beginning January 1, 2008. The Company has reviewed the requirements of SFAS 157 and does not expect its adoption to impact financial position, results of operations or cash flows.





QUESTAR MARKET RESOURCES 2007 FORM 10-K

41


SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities”

The FASB issued SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities in February 2007.” SFAS 159 permits the measurement of certain financial instruments at fair value. Entities may choose to measure eligible items at fair value at certain election dates and report unrealized gains and losses on such items for each subsequent reporting period. SFAS 159 will be effective for Questar beginning January 1, 2008. The Company has reviewed the requirements of SFAS 159 and does not expect its adoption to impact financial position, results of operations or cash flows.


SFAS 141(R) “Business Combinations”

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


SFAS 160 “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51”

SFAS 160 requires ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated balance sheets within shareholders’ equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on  the consolidated statements of income, changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently; and any retained noncontrolling equity investment in the former subsidiary be initially  measured at fair value. SFAS 160 is effective beginning January 1, 2009. The Company is currently evaluating the impact of SFAS 160.


Reclassifications

Certain reclassifications were made to prior-year consolidated financial statements to conform with the 2007 presentation.


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


Note 2 – Share-Based Compensation


Prior to January 1, 2006, Questar and the Company accounted for share-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion (APBO) 25 “Accounting for Stock Issued to Employees” and related interpretations. No compensation cost was recorded for stock options because the exercise price equaled the market price on the date of grant. Under SFAS 123R “Share Based Payment,” the fair value of stock options was determined on the grant date using the Black-Scholes-Merton option-valuation model. The granting of restricted shares results in recognition of compensation cost under APBO 25 and SFAS 123R. Restricted shares are valued at the grant-date market price and amortized to expense over the vesting period. Market Resources uses an accelerated method in recognizing share-based compensation costs with graded-vesting periods.


Questar and the Company implemented SFAS 123R effective January 1, 2006, and chose the modified prospective phase-in method of accounting by SFAS 123R. The modified prospective phase-in method requires recognition of compensation costs for all share-based payments granted, modified or settled after January 1, 2006, as well as for any awards that were granted prior to the implementation date for which the required service has not yet been performed. Adopting SFAS 123R resulted in lower income before income taxes and net income than if the Company had continued to account for share-based compensation under APBO 25 due to expensing the fair value of stock options. Income before income taxes and net income were approximately $0.7 million and 0.4 million lower, respectively, for the year ended December 31, 2007. Income before income taxes and net income for the year ended December 31, 2006, were approximately $0.7 million and $0.4 million lower, respectively. The pro forma share-based compen sation expense impact for the year of 2005 was approximately $0.8 million. Amortized share-based compensation associated with unvested restricted shares amounted to $8.2 million for the year ended December 31, 2007.


There were 60,000 stock options issued to Market Resources’ LTSIP in 2007. Fair value was calculated using the Black-Scholes-Merton model on the grant date.


Transactions involving stock options granted to employees of Market Resources under the LTSIP are summarized below:




QUESTAR MARKET RESOURCES 2007 FORM 10-K

42



 


Options

Outstanding



Price Range

Weighted

Average

Price

Balance at January 1, 2006 

1,802,638 

$7.50 – $38.57 

 $15.09 

Exercised 

(364,496)

7.50 –   17.55 

 11.57 

Balance a December 31, 2006

1,438,142 

7.50 –  38.57 

 15.97 

Granted 

60,000 

41.08 

 41.08 

Exercised 

(157,464)

7.50 –  17.55 

 12.71 

Employee transferred 

(16,064)

10.69 

 10.69 

Forfeited

(1,000)

14.01 

 14.01 

Balance at December 31, 2007 

1,323,614 

$7.50 – $41.08 

 $17.57 


The number of unvested stock options held by Market Resources employees increased by 47,500 shares to 260,000 in 2007.


 

Options Outstanding

Options Exercisable

Unvested Options



Range of exercise

prices



Number

outstanding at Dec. 31, 2007

Weighted-average remaining term in years


Weighted-average exercise price



Number exercisable at

Dec. 31, 2007



Weighted-average exercise price



Number unvested at Dec. 31, 2007


Weighted-average exercise price

$  7.50 - $  8.50 

137,378 

1.7 

$  7.96 

137,378 

$  7.96 

 

 

9.57 -   11.98 

390,742 

4.0 

11.67 

390,742 

11.67 

 

 

13.56  -  14.86 

514,418 

4.5 

13.70 

514,418 

13.70 

 

 

17.55 -   24.33 

21,076 

6.3 

17.55 

21,076 

17.55 

 

 

$38.57 - $41.08 

260,000 

5.4 

39.15 

 

 

260,000 

$39.15 

 

1,323,614 

4.3 

$17.57 

1,063,614 

$12.29 

260,000 

$39.15 


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


 

Restricted

 Shares

Outstanding

Price Range

Weighted Average

Price

Balance at January 1, 2006 

354,482 

$13.56 - $43.02 

$20.64 

Granted 

231,580 

35.20 -  44.77 

37.10 

Distributed 

(121,326)

13.56 -   43.02 

17.85 

Forfeited 

(4,990)

14.36 -   38.00 

31.14 

Balance at December 31, 2006

459,746 

14.36 –   44.77 

29.54 

Granted 

290,740 

38.96 –   55.42 

46.02 

Distributed 

(160,606)

14.36 –   49.98 

23.40 

Forfeited 

(26,702)

18.45 –   49.97 

35.22 

Balance at December 31, 2007

563,178 

$14.36 – $55.42 

$39.40 






QUESTAR MARKET RESOURCES 2007 FORM 10-K

43


Note 3 – Asset Retirement Obligations (ARO)


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


 

2007

2006

 

(in millions)

ARO liability at January 1,

$128.3 

$ 74.3 

Accretion

8.1 

6.9 

Liabilities incurred

8.9 

11.1 

Revisions

1.5 

38.2 

Liabilities settled

(1.5)

(2.2)

ARO liability at December 31,

$145.3 

$128.3 


Wexpro activities are governed by the Wexpro Agreement. The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is 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). Accordingly, Wexpro collects from Questar Gas and deposits in trust funds related to estimated ARO costs. The funds are used to satisfy retirement obligations as the properties are abandoned. At December 31, 2007, approximately $7.8 million was held in this trust invested primarily in a short-term bond index fund.


Note 4 – Capitalized Exploratory Well Costs


Net changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the period:


 

2007

2006

2005

 

(in millions)

Balance at January 1,

$10.5 

$16.5 

$14.6 

Additions to capitalized exploratory well costs pending the

 

 

 

  determination of proved reserves

1.5 

10.5 

9.8 

Reclassifications to property, plant and equipment after the

 

 

 

  determination of proved reserves

 

(5.0)

(5.7)

Capitalized exploratory well costs charged to expense, incurred in

    prior periods

(10.5)

(11.5)

(2.2)

Balance at December 31,

$  1.5 

$10.5 

$16.5 


The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and any projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:


 

December 31,

 

2007

2006

2005

 

(in millions)

Capitalized exploratory well costs that have been capitalized

 

 

 

  one year or less

$1.5 

$10.5 

$  9.8 

Capitalized exploratory well costs that have been capitalized

 

 

 

  longer than one year

 

 

6.7 

Balance at end of period

$1.5 

$10.5 

$16.5 




QUESTAR MARKET RESOURCES 2007 FORM 10-K

44






Note 5 – Debt


Questar makes loans to Market Resources under a short-term borrowing arrangement. Short-term notes payable to Questar are subordinated to obligations under the revolving credit agreement. Short-term notes payable to Questar amounted to $118.9 million with an interest rate of 5.36% and $142.6 million with an interest rate of 5.44% at December 31, 2007 and 2006, respectively.


All long-term notes and the term loan are unsecured obligations and rank equally with all other unsecured liabilities. Market Resources revolving credit agreement had $100 million outstanding at December 31, 2007 and zero a year earlier. This credit agreement carries an annual commitment fee of 0.115% of the unused balance. At December 31, 2007, Market Resources could pay dividends of $851.0 million without violating the terms of their debt covenants.


On May 11, 2006, Market Resources sold $250 million principal amount of 6.05% Notes due 2016. Net proceeds of $247 million were used for general corporate purposes including the June 14, 2006, early extinguishment of $200 million of 7% Notes due 2007. Market Resources recorded a $1.7 million charge related to the early extinguishment. Long-term debt outstanding as of December 31, 2007 and 2006 is listed in the table below:


 

December 31,

 

2007

2006

 

(in millions)

7.5% notes due 2011

$150.0 

$150.0 

6.05% notes due 2016

250.0 

250.0 

Revolving term loan, 5.55% at December 31, due 2012

100.0 

 

  Total long-term debt outstanding

500.0 

400.0 

  Less unamortized-debt discount

(0.7)

(0.8)

Total long-term debt outstanding

$499.3 

$399.2 


The Company’s 7.5% notes and revolving term loan are scheduled to be repaid within five years following December 31, 2007.


Note 6 – Financial Instruments and Risk Management


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


 

December 31, 2007

December 31, 2006

 

Carrying

Estimated

Carrying

Estimated

 

Value

Fair Value

Value

Fair Value

 

(in millions)

Financial assets

 

 

 

 

Cash and cash equivalents

 

 

$  18.2 

$  18.2 

Notes receivable from Questar

$103.2 

$103.2 

69.8 

69.8 

Fair value of derivative contracts

85.9 

85.9 

204.5 

204.5 

Financial liabilities

 

 

 

 

Notes payable to Questar

118.9 

118.9 

142.6 

142.6 

Long-term debt

500.0 

503.1 

400.0 

412.8 

Fair value of derivative contracts

31.4 

31.4 

0.8 

0.8 


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.





QUESTAR MARKET RESOURCES 2007 FORM 10-K

45


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


Derivative contracts – fair value of the contracts is based on market prices as posted on the NYMEX from the last trading day of the year. Gas derivatives are structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. As of December 31, 2007, Market Resources held gas-price-derivative instruments covering the price exposure for about 245.0 million MMBtu of natural gas, 2.0 million barrels of oil, 5.0 million gallons of NGL and basis-only swaps on an additional 40.8 Bcf. About $68.8 million of the fair value of all contracts as of December 31, 2007, will settle and be reclassified from other comprehensive income in the next 12 months. A year earlier Market Resources derivatives covered the price exposure for 204.2 million MMBtu of natural gas, 1.8 million barrels of oil, 22.7 million gallons of NGL and basis-only swaps on an additional 47.7 Bcf.


At December 31, 2007, the Company reported the fair value of derivative assets, net of liabilities, of $54.5 million. The offset to the net derivative assets, net of income taxes, was a $31.0 million unrealized gain on derivatives recorded in accumulated other comprehensive income in the Common Shareholder’s Equity section of the consolidated balance sheet. During 2007, $153.9 million of fair value associated with gas-price-derivative contracts settled and was reclassified into income. The ineffective portion of derivative transactions recognized in earnings was not significant. The fair-value calculation of gas- and oil-price derivatives does not consider changes in the fair value of the corresponding scheduled equity physical transactions, (i.e., the correlation between index price and the price realized for the physical delivery of gas or oil).


Note 7 – Income Taxes


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


 

Year Ended December 31,

 

2007

2006

2005

 

(in millions)

Federal

 

 

 

  Current

$  56.4 

$  89.3 

$  65.5 

  Deferred

166.1 

98.5 

71.8 

State

 

 

 

  Current

1.9 

6.6 

5.4 

  Deferred

16.9 

12.2 

7.4 

  

$241.3 

$206.6 

$150.1 


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


 

Year Ended December 31,

 

2007

2006

2005

Federal income tax statutory rate

35.0%

35.0%

35.0%

State income taxes, net of federal income tax benefit

1.8 

2.2 

2.0 

Domestic production benefit

(0.3)

(0.4)

(0.3)

Percentage depletion

 

(0.1)

(0.1)

Other

(0.1)

 

0.2 

  Effective income tax rate

36.4%

36.7%

36.8%


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




QUESTAR MARKET RESOURCES 2007 FORM 10-K

46



 

December 31,

 

2007

2006

 

(in millions)

Deferred tax liabilities

 

 

Property, plant and equipment

$744.7 

$565.0 

Energy-price derivatives

 

18.9 

  Total deferred tax liabilities

744.7 

583.9 

Deferred tax assets

 

 

Energy-price derivatives

6.0 

 

Employee benefits and compensation costs

7.3 

4.9 

  Total deferred tax assets

13.3 

4.9 

    Net deferred income taxes

$731.4 

$579.0 

Deferred income taxes – current liability

 

 

Energy-price derivatives

$ 26.2 

$ 58.3 

Other

(12.9)

(16.6)

  Deferred income taxes – current liability

$ 13.3 

$ 41.7 


Note 8 – Commitments and Contingencies


Market Resources is involved in various commercial and regulatory claims and litigation and other legal proceedings that arise in the ordinary course of its business. Management does not believe any of them will have a material adverse effect on the Company’s financial position, results of operations or cash flows. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. Disclosures are provided for contingencies reasonably likely to occur which would have a material adverse effect on the Company’s financial position, results of operations or cash flows. Some of the claims involve highly complex issues relating to liability, damages and other matters subject to substantial uncertainties and, therefore, the probability of liability or an estimate of loss cannot be reasonably determined.


Subsidiaries of Market Resources have contracted for firm-transportation services with various third-party pipelines through 2028. Market conditions and competition may prevent full recovery of the cost. Annual payments and the years covered are as follows:


 

(in millions)

2008

$  8.7 

2009

7.9 

2010

7.6 

2011

7.3 

2012

5.3 

2013 through 2028

18.7 


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 expired October 31, 2007. The minimum future payments under the terms of long-term operating leases for the Company’s primary office locations for the six years following December 31, 2007, are as follows:




QUESTAR MARKET RESOURCES 2007 FORM 10-K

47



 

(in millions)

2008

$3.6 

2009

3.6 

2010

3.3 

2011

2.8 

2012

1.8 

2013

1.3 


Total rental expense amounted to $3.0 million in 2007, $2.5 million in 2006 and $2.2 million in 2005.


Environmental Claims

In 2004, the Environmental Protection Agency (EPA) issued two separate compliance orders alleging that Gas Management did not comply with regulatory requirements adopted to implement the federal Clean Air Act. Both orders involved facilities in the Uinta Basin of eastern Utah that were purchased by Questar E&P in mid-2001. The EPA contends such facilities are located within “Indian Country” and are subject to federal Clean Air Act requirements, rather than air quality rules adopted by the state of Utah. Generally, EPA contends that Gas Management failed to obtain necessary pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations, in violation of federal requirements. Gas Management has generally contested EPA’s allegations, and believes that the permitting and regulatory requirements at issue can be legally avoided under Utah law. EPA has broadened its allegations to include additional potential ongoing violatio ns of the Clean Air Act for the referenced facilities. Other Gas Management facilities in the Uinta Basin have been added to the civil penalty discussions with the EPA, with similar allegations of Clean Air Act violations. These potential violations will likely result in civil penalties of an unknown and undetermined amount in excess of $100,000. The parties are engaged in settlement discussions and have signed a tolling agreement to extend the statute of limitations for filing any claims. Because of the complexities and uncertainties of this dispute, it is difficult to predict the likely potential outcomes; however, management believes the company has accrued an appropriate liability for this claim.


Note 9 – Employee Benefits


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 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 pension plan approximately equal to the yearly expense. Questar also has a nonqualified pension plan that covers certain management employees in addition to the qualified pension plan. The nonqualified pension plan provides for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee above the benefit limit defined by the Internal Revenue Service for the qualified plan. The no nqualified pension plan is unfunded. Claims are paid from the Company’s general funds. Qualified pension 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. Pension expense was $4.6 million in 2007, $4.9 million in 2006 and $3.3 million in 2005.


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, 2007 and 2006, Questar’s projected 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. A third party consultant calculates the projected benefit obligation. The cost of postretirement benefits other than pensions was $1.3 million in 2007 and 2006 and $1.2 million in 2005.




QUESTAR MARKET RESOURCES 2007 FORM 10-K

48



The Company’s portion of plan assets and benefit obligations related to post-retirement 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, 2007 and 2006, Questar’s accumulated benefit obligation exceeded the fair value of plan assets.


Employee Investment Plan  

Market Resources subsidiaries participate in Questar’s Employee Investment Plan (EIP).The EIP allows eligible employees to purchase shares of Questar common stock or other investments through payroll deduction at the current fair market value on the transaction date. The Company currently contributes an overall match of 100% of employees’ pre-tax purchases up to a maximum of 6% of their qualifying earnings. In addition, the Company contributes $200 annually to the EIP for each eligible employee. Beginning in 2005, the EIP trustee purchased Questar shares on the open market as cash contributions are received. The Company’s expense equaled its matching contribution of $3.5 million in 2007, $2.4 million in 2006 and $2.1 million in 2005.


Note 10 – Related Party Transactions


Market Resources receives a portion of its revenues from services provided to affiliate, Questar Gas. The Company received $171.6 million in 2007, $176.4 million in 2006 and $159.5 million in 2005 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 11).


Market Resources pays Questar for certain administrative services. These payments were $16.8 million in 2007, $11.5 million in 2006 and $13.0 million in 2005 and were included in operating 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 2007, $3.7 million in 2006 and $2.8 million in 2005 for these services. Energy Trading purchased and marketed liquids extracted from Questar Pipeline’s transportation lines in 2005 paying $3.6 million. Questar InfoComm, an affiliated company that previously provided some information technology and communication services to Market Resources was paid $0.2 million in 2005.


Market Resources has a lease with Questar for space in an office building located in Salt Lake City, Utah, that expired 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 $1.0 million in 2007, $0.7 million in 2006 and $0.8 million in 2005.


The Company received interest income from affiliated companies of $4.5 million in 2007, $3.4 million in 2006 and $0.8 million in 2005. Market Resources incurred interest expense to affiliated companies of $6.8 million in 2007, $4.4 million in 2006 and $3.8 million in 2005.


Note 11 – Wexpro Agreement


Wexpro’s operations are subject to the terms of the Wexpro Agreement. The agreement was effective August 1, 1981, and sets forth the rights of Questar Gas utility operations to receive certain benefits from Wexpro’s operations. The agreement was approved by the PSCU and PSCW in 1981 and affirmed by the Supreme Court of Utah in 1983. Major provisions of the agreement are as follows.


a. Wexpro conducts gas-development drilling on a finite group of productive gas properties, as defined in the agreement, and bears any costs of dry holes. Natural gas produced from successful drilling on these properties is delivered to Questar Gas. Wexpro is reimbursed for the costs of producing the natural gas plus a return on its investment in successful wells. The after-tax return allowed Wexpro is adjusted annually and is approximately 20.9%.


b. Wexpro operates certain natural gas properties for Questar Gas. Wexpro is reimbursed for its costs of operating these properties, including a rate of return on any investment it makes. This after-tax rate of return is adjusted annually and is approximately 12.9%.


c. Production from a finite group of oil-producing properties is sold at market prices with the revenues used to recover operating expenses and to give Wexpro a return on its investment. The after-tax rate of return is adjusted annually and is approximately




QUESTAR MARKET RESOURCES 2007 FORM 10-K

49


12.9%. Any net income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas, with Wexpro retaining 46%.


d. Wexpro conducts developmental-oil drilling on productive oil properties and bears any costs of dry holes. Oil discovered from these properties is sold at market prices with the revenues used to recover operating expenses and to give Wexpro a return on its investment in successful wells. The after-tax rate of return is adjusted annually and is approximately 17.9%. Any net income remaining after recovery of expenses and Wexpro’s return on investment is divided between Wexpro and Questar Gas with Wexpro retaining 46%. Questar Gas received oil-income sharing of $4.9 million in 2007, $5.5 million in 2006 and $6.1 million in 2005.


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


Wexpro’s investment base, net of depreciation and deferred income taxes, and the yearly average rate of return for 2007 and the previous two years are shown in the table below:


 

2007

2006

2005

Wexpro’s net investment base (in millions)

$300.4 

$260.6 

$206.3 

Average annual rate of return (after tax)

19.9%

19.9%

20.4%


Note 12 – Operations by Line of Business


Market Resources’ major lines of business include gas and oil exploration and production (Questar E&P and Wexpro), midstream field services (Gas Management) and energy marketing (Energy Trading). 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, 2007:


 

Market Resources

Consolidated

Interco.

Transactions

Questar

E&P

Wexpro

Gas

Management

Energy

Trading

 

 

(in millions)

2007

 

Revenues

 

 

 

 

 

 

  From unaffiliated customers

$1,671.3

 

$   956.0

$  21.6

$189.3

$504.4

  From affiliated companies

172.1

($484.7)

 

155.7

17.0

484.1

     Total Revenues

1,843.4

(484.7)

956.0

177.3

206.3

988.5

Operating expenses

 

 

 

 

 

 

  Cost of natural gas and other products sold

474.7

(482.8)

2.2

 

 

955.3

  Operating and maintenance

187.9

(1.1)

87.9

16.5

83.6

1.0

  General and administrative

91.3

(0.8)

56.3

14.7

17.2

3.9

  Production and other taxes

81.6

 

60.1

20.0

1.4

0.1

  Depreciation, depletion and amortization

295.1

 

243.5

31.2

19.1

1.3

  Other operating expenses

38.1

 

32.8

4.9

0.4

 

     Total operating expenses

1,168.7

(484.7)

482.8

87.3

121.7

961.6

Net (loss) from asset sales

(1.3)

 

(0.6)

(0.7)

 

 

  Operating income

673.4

 

472.6

89.3

84.6

26.9

Interest and other income

15.4

(26.9)

6.2

1.9

0.2

34.0

Income from unconsolidated affiliates

8.9

 

0.4

 

8.5

 

Interest expense

(35.6)

26.9

(25.2)

(2.0)

(6.9)

(28.4)

Income tax expense

(241.3)

 

(168.5)

(30.0)

(31.1)

(11.7)




QUESTAR MARKET RESOURCES 2007 FORM 10-K

50





  Net income

$   420.8

 

$   285.5

$  59.2

$  55.3

$  20.8

Identifiable assets

$3,806.4

 

$2,524.5

$481.1

$494.2

$306.6

Investment in unconsolidated affiliates

52.8

 

 

 

52.8

 

Capital expenditures

943.9

 

708.5

105.0

128.3

2.1

Goodwill

60.9

 

60.9

 

 

 

2006

 

Revenues

 

 

 

 

 

 

  From unaffiliated customers

$1,659.4 

 

$  815.7 

$   19.7 

$168.0 

$ 656.0 

  From affiliated companies

176.4 

($687.8)

 

150.5 

15.9 

697.8 

     Total Revenues

1,835.8 

(687.8)

815.7 

170.2 

183.9 

1,353.8 

Operating expenses

 

 

 

 

 

 

  Cost of natural gas and other products sold

652.6 

(686.0)

2.8 

 

 

1,335.8 

  Operating and maintenance

180.4 

(1.1)

73.6 

14.7 

92.4 

0.8 

  General and administrative

69.2 

(0.7)

42.4 

11.3 

12.2 

4.0 

  Production and other taxes

89.4 

 

58.3 

30.3 

0.6 

0.2 

  Depreciation, depletion and amortization

235.0 

 

185.7 

33.1 

15.3 

0.9 

  Other operating expenses

47.5 

 

42.0 

5.5 

 

 

     Total operating expenses

1,274.1 

(687.8)

404.8 

94.9 

120.5 

1,341.7 

Net gain (loss) from asset sales

25.2 

 

24.3 

(0.1)

1.0 

 

  Operating income

586.9 

 

435.2 

75.2 

64.4 

12.1 

Interest and other income (expense)

2.2 

(27.0)

(3.7)

1.3 

 

31.6 

Income from unconsolidated affiliates

7.5 

 

0.4 

 

7.1 

 

Interest expense

(33.9)

27.0 

(27.1)

(0.5)

(4.7)

(28.6)

Income tax expense

(206.6)

 

(150.9)

(26.0)

(24.2)

(5.5)

  Net income

$   356.1 

 

$   253.9 

$  50.0 

$  42.6 

$    9.6 

Identifiable assets

$3,249.6 

 

$2,169.9 

$397.1 

$377.1 

$305.5 

Investment in unconsolidated affiliates

37.5 

 

 

 

37.3 

0.2 

Capital expenditures

752.7 

 

586.3 

82.7 

82.2 

1.5 

Goodwill

60.9 

 

60.9

 

 

 

2005

 

Revenues

 

 

 

 

 

 

  From unaffiliated customers

$1,668.7 

 

$   620.6 

$    21.7 

$   141.5 

$  884.9 

  From affiliated companies

 159.5 

($618.9)

 

132.3 

13.7 

632.4 

     Total Revenues

1,828.2 

(618.9)

620.6 

154.0 

155.2 

1,517.3 

Operating expenses

 

 

 

 

 

 

  Cost of natural gas and other products sold

888.3 

(617.6)

4.2 

 

 

1,501.7 

  Operating and maintenance

158.6 

(0.6)

61.8 

11.2 

85.2 

1.0 

  General and administrative

54.6 

(0.7)

33.9 

10.0 

7.5 

3.9 

  Production and other taxes

102.2 

 

68.7 

32.6 

0.7 

0.2 

  Depreciation, depletion and amortization

173.8 

 

134.7 

26.9 

11.3 

0.9 

  Other operating expenses

25.5 

 

18.8 

6.7 

 

 

     Total operating expenses

1,403.0 

(618.9)

322.1 

87.4 

104.7 

1,507.7 

Net gain (loss) from asset sales

0.9 

 

1.1 

(0.2)

 

 

  Operating income

426.1 

 

299.6 

66.4 

50.5 

9.6 




QUESTAR MARKET RESOURCES 2007 FORM 10-K

51





Interest and other income

5.6 

(26.2)

0.6 

0.9 

0.3 

30.0 

Income from unconsolidated affiliates

7.5 

 

0.3 

 

7.2 

 

Interest expense

(30.9)

26.2 

(23.7)

(0.1)

(3.1)

(30.2)

Income tax expense

(150.1)

 

(104.0)

(23.5)

(19.2)

(3.4)

  Net income

$   258.2 

 

$   172.8 

$    43.7 

$    35.7 

$      6.0 

Identifiable assets

$2,621.3 

 

$1,656.7 

$  331.2 

$  301.8 

$ 331.6 

Investment in unconsolidated affiliates

30.7 

 

0.1 

 

30.3 

0.3 

Capital expenditures

576.2 

 

424.2 

57.8 

93.3 

0.9 

Goodwill

61.5 

 

61.5

 

 

 


Note 13 – Subsequent Event - Questar E&P Property Acquisition


On January 31, 2008, Questar E&P entered into agreements with multiple private sellers to acquire two significant natural gas development properties in northwest Louisiana for an aggregate purchase price of $655 million. The transactions will be subject to usual and customary closing and post-closing adjustments. In February 2008, Market Resources established a $700 million floating-rate term-loan credit facility, due August 15, 2008, to finance the purchase of the Louisiana natural gas development properties. Market Resources plans to expand its current revolving credit facility to $800 million and issue up to $500 million of additional long-term debt to retire the $700 million term loan credit facility.


Note 14 – Quarterly Financial Information (Unaudited)


Following is a summary of quarterly financial information:


 

First

Second

Third

Fourth

 

 

Quarter

Quarter

Quarter

Quarter

Year

 

(in millions)

2007

 

 

 

 

 

Revenues  

$478.7 

$430.6 

$411.8 

$522.3 

$1,843.4 

Operating income

165.5 

173.1 

167.7 

167.1 

673.4 

Net income

109.5 

102.1 

108.7 

100.5 

420.8 

2006

 

 

 

 

 

Revenues  

$467.5 

$424.3 

$467.9 

$476.1 

$1,835.8 

Operating income

155.0 

138.6 

156.2 

137.1 

586.9 

Net income

94.7 

79.3 

92.0 

90.1 

356.1 


Note 15 – 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:




QUESTAR MARKET RESOURCES 2007 FORM 10-K

52



 

December 31,

 

2007

2006

 

(in millions)

Proved properties

$3,306.9 

$2,646.6 

Unproved properties

55.6 

42.7 

Support equipment and facilities

23.3 

18.5 

 

3,385.8 

2,707.8 

Accumulated depreciation, depletion and amortization

(1,114.3)

(901.5)

 

$2,271.5 

$1,806.3 


Costs Incurred

The costs incurred in gas and oil exploration and development activities are displayed in the table below. The development costs include expenditures to develop a portion of the proved undeveloped reserves reported at the end of the prior year. These costs were $125.8 million in 2007, $109.2 million in 2006 and $116.7 million in 2005.


 

Year Ended December 31,

 

2007

2006

2005

 

(in millions)

Property acquisition

 

 

 

  Unproved

$  28.9 

$  22.5 

$13.7 

  Proved

45.1 

20.6 

3.4 

Exploration (capitalized and expensed)

25.4 

34.5 

49.4 

Development

641.7 

581.2 

381.7 

 

$741.1 

$658.8 

$448.2 


Results of Operation

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


 

Year Ended December 31,

 

2007

2006

2005

 

(in millions)

Revenues

$956.0 

$815.7 

$620.6 

Production expenses

148.0 

131.9 

130.5 

Exploration expenses

22.0 

34.4 

11.1 

Depreciation, depletion and amortization

243.5 

185.7 

134.7 

Abandonment and impairment

10.8 

7.6 

7.7 

  Total expenses

424.3 

359.6 

284.0 

Revenues less expenses

531.7 

456.1 

336.6 

Income taxes

(197.3)

(170.1)

(126.6)

Results of operation before corporate overhead

  and interest expenses

$334.4 


$286.0 


$210.0 


Estimated Quantities of Proved Gas and Oil Reserves

Estimates of the Company’s proved gas and oil reserves have been prepared by Ryder Scott Company, H. J. Gruy and Associates, Inc. and Netherland, Sewell & Associates, Inc., independent reservoir engineers, in accordance with the SEC’s Regulation S-X and SFAS 69 “Disclosures about Oil and Gas Producing Activities.” The table below summarizes the changes in




QUESTAR MARKET RESOURCES 2007 FORM 10-K

53


the estimated net quantities of proved natural gas, oil and NGL reserves for each of the three years in the period ended December 31, 2007. The quantities reported are based on existing economic and operating conditions at the time the estimates were made. All gas and oil reserves reported are located in the United States. The Company does not have any long-term supply contracts with foreign governments or reserves of equity investees.


 

 

 

Natural Gas

 

Natural Gas

Oil and NGL

Equivalents

 

(Bcf)

(MMbbl)

(Bcfe)(a)

Proved Reserves

 

 

 

Balance at January 1, 2005

1,270.5 

27.2 

1,434.0 

Revisions -

 

 

 

  Previous estimates

11.9 

(0.7)

7.9 

  Pinedale increased-density(b)

31.5 

0.3 

33.0 

Extensions and discoveries

110.9 

1.4 

119.3 

Purchase of reserves in place

0.3 

0.1 

0.7 

Sale of reserves in place

(0.3)

 

(0.3)

Production

(100.0)

(2.4)

(114.2)

Balance at December 31, 2005

1,324.8 

25.9 

1,480.4 

Revisions -

 

 

 

  Previous estimates

(38.9)

2.6 

(23.8)

  Pinedale increased-density(b)

163.0 

1.2 

170.4 

Extensions and discoveries

119.1 

1.2 

126.6 

Purchase of reserves in place

9.8 

0.1 

10.2 

Sale of reserves in place

(2.7)

 

(2.8)

Production

(113.9)

(2.6)

(129.6)

Balance at December 31, 2006

1,461.2 

28.4 

1,631.4 

Revisions -

 

 

 

  Previous estimates

26.3 

3.3 

46.2 

  Pinedale increased-density(b)

120.6 

1.0 

126.8 

Extensions and discoveries

172.6 

3.3 

192.7 

Purchase of reserves in place

16.0 

0.2 

17.1 

Sale of reserves in place

(6.3)

 

(6.4)

Production

(121.9)

(3.0)

(140.2)

Balance at December 31, 2007

1,668.5 

33.2 

1,867.6 

 

 

 

 

Proved-Developed Reserves

 

 

 

Balance at January 1, 2005

680.6 

21.3 

808.3 

Balance at December 31, 2005

792.0 

21.4 

920.5 

Balance at December 31, 2006

852.0 

23.1 

990.7 

Balance at December 31, 2007

987.4 

26.7 

1,147.4 


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


(b)Estimates of the quantity of proved reserves from the Company’s Pinedale Anticline leasehold in western Wyoming have changed substantially over time as a result of numerous factors including, but not limited to, additional development drilling activity, producing well performance and an improved understanding of Lance Pool reservoir characteristics. The continued




QUESTAR MARKET RESOURCES 2007 FORM 10-K

54


analysis of new data has led to progressive increases in estimates of original gas-in-place in the Lance Pool reservoirs at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. The WOGCC has approved 10-acre-density drilling for Lance Pool wells on about 12,700 (gross) of the Company’s 18,208 acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the estimated productive limits of the Company’s core acreage in the field. In January 2008, the WOGCC approved five-acre-density drilling for Lance Pool wells on about 4,200 gross acres of Market Resources Pinedale leasehold. If five-acre-density development is appropriate for a majority of its leasehold, the company currently estimates up to an additional 1,600 wells will be required to fully develop the Lance Pool on its acreage. The Company will continue to disclose future revisions to proved rese rves associated with Pinedale increased-density drilling separately.


Standardized Measure of Future Net Cash Flows Relating to Proved Reserves

Future net cash flows were calculated at December 31 using year-end prices and known contract-price changes. The year-end prices do not include any impact of hedging activities. The average year-end price per Mcf of proved natural gas reserves was $6.01 in 2007, $4.47 in 2006 and $7.80 in 2005. The average year-end price per barrel of proved oil and NGL reserves combined was $80.86 in 2007, $51.49 in 2006 and $56.47 in 2005. Year-end production costs, development costs and appropriate statutory income tax rates, with consideration of future tax rates already legislated, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop booked proved undeveloped reserves are $230.7 million in 2008, $299.7 million in 2009 and $159.7 million in 2010. At the end of this three-year period the Company expects to have evaluated about 53% of the cu rrent booked proved undeveloped reserves.


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


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


 

Year Ended December 31,

 

2007

2006

2005

 

(in millions)

Future cash inflows

$12,704.3 

$  7,985.1 

$11,791.1 

Future production costs

(2,863.4)

(2,133.0)

(2,465.8)

Future development costs

(1,232.4)

(1,026.9)

(725.7)

Future income tax expenses

(2,668.8)

(1,396.2)

(2,930.3)

  Future net cash flows

5,939.7 

3,429.0 

5,669.3 

10% annual discount to reflect timing of net cash flows

(3,105.7)

(1,861.2)

(2,962.2)

Standardized measure of discounted future net cash flows

$ 2,834.0 

$  1,567.8 

$  2,707.1 


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


 

Year Ended December 31,

 

2007

2006

2005

 

(in millions)

Balance at January 1,

$1,567.8 

$2,707.1 

$1,760.5 

Sales of gas and oil produced, net of production costs

(808.0)

(683.8)

(490.1)

Net changes in prices and production costs

1,554.6 

(1,994.3)

1,183.6 

Extensions and discoveries, less related costs

523.6 

233.1 

330.4 

Revisions of quantity estimates

470.0 

269.9 

113.3 

Net purchases and sales of reserves in place

41.8 

(7.5)

0.5 




QUESTAR MARKET RESOURCES 2007 FORM 10-K

55





Cost to develop proved undeveloped reserves

125.8 

109.2 

116.7 

Change in future development

(214.5)

(259.6)

(120.3)

Accretion of discount

221.0

411.0 

176.1 

Net change in income taxes

(635.0)

760.8 

(440.3)

Other

(13.1)

21.9 

76.7 

  Net change

1,266.2

(1,139.3)

946.6 

Balance at December 31,

$2,834.0

$1,567.8 

$2,707.1 


Cost-of-Service Activities

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


Capitalized Costs

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


 

December 31,

 

2007

2006

 

(in millions)

Wexpro

$434.7 

$353.2 

Questar Gas

12.2 

13.2 

 

$446.9 

$366.4 


Costs Incurred

Costs incurred by Wexpro for cost-of-service gas and oil-producing activities were $110.7 million in 2007, $100.3 million in 2006 and $57.0 million in 2005.


Results of Operation

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


 

Year Ended December 31,

 

2007

2006

2005

 

(in millions)

Revenues

 

 

 

  From unaffiliated companies

$  21.6 

$  19.7 

$  21.7 

  From affiliates(a)

155.7 

150.5 

132.3 

  Total revenues

177.3 

170.2 

154.0 

Production expenses

41.4 

50.5 

50.0 

Depreciation and amortization

31.2 

33.1 

26.9 

Abandonment and impairment

 

 

0.2 

Exploration

 

 

0.4 

  Total expenses

72.6 

83.6 

77.5 

Revenues less expenses

104.7 

86.6 

76.5 

Income taxes

(35.2)

(29.6)

(26.8)

  Results of operation before corporate overhead and interest expense

$  69.5 

$  57.0 

$  49.7 


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




QUESTAR MARKET RESOURCES 2007 FORM 10-K

56



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

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


 

 

 

Natural Gas

 

Natural Gas

Oil and NGL

Equivalents

 

(Bcf)

(MMbbl)

(Bcfe)(a)

Proved Reserves

 

 

 

Balance at January 1, 2005

531.1 

4.2 

556.3 

Revisions-

 

 

 

  Previous estimates

(30.8)

(0.1)

(32.2)

  Pinedale increased-density(b)

7.8 

 

8.1 

Extensions and discoveries

29.2 

0.2 

30.7 

Production

(40.0)

(0.4)

(42.4)

Balance at December 31, 2005

497.3 

3.9 

520.5 

Revisions-

 

 

 

  Previous estimates

22.3 

(0.1)

21.5 

  Pinedale increased-density(b)

100.0 

0.8 

104.6 

Extensions and discoveries

39.8 

0.2 

41.3 

Production

(38.8)

(0.4)

(40.9)

Balance at December 31, 2006

620.6 

4.4 

647.0 

Revisions-

 

 

 

  Previous estimates

(29.9)

 

(30.0)

  Pinedale increased-density(b)

24.6 

0.2 

25.9 

Extensions and discoveries

35.5 

0.1 

36.4 

Production

(34.9)

(0.4)

(37.4)

Balance at December 31, 2007

615.9 

4.3 

641.9 

 

 

 

 

Proved-Developed Reserves

 

 

 

Balance at January 1, 2005

409.2 

3.2 

428.4 

Balance at December 31, 2005

406.6 

3.1 

425.2 

Balance at December 31, 2006

440.6 

2.9 

458.2 

Balance at December 31, 2007

439.4 

2.9 

456.9 


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

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




QUESTAR MARKET RESOURCES 2007 FORM 10-K

57



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 millions)

Year Ended December 31, 2007

 

 

 

Allowance for bad debts

$4.3 

$0.1 

($1.1)

$3.3 

Year Ended December 31, 2006

 

 

 

Allowance for bad debts

2.9 

1.4 

 

4.3 

Year Ended December 31, 2005

 

 

 

Allowance for bad debts

2.8 

0.1 

 

2.9 


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 (T.)  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 December 31, 2007, covered by the report (the Evaluation Date). The effectiveness of the Company’s internal control over financial reporting was assessed using criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework. 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 E xecutive 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.


This annual report is not required to and does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.


Changes in Internal Controls

There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.


Management’s Assessment of Internal Control Over Financial Reporting

Market Resources management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(e). The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. The criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework were used to make this assessment. We believe that the Company’s internal control over financial reporting as of December 31, 2007, is effective based on those criteria.





QUESTAR MARKET RESOURCES 2007 FORM 10-K

58


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:


 

2007

2006

Audit Fees

$1,217,900 

$1,392,407 

Market Resources Portion

681,081 

824,370 

Audit-related Fees

95,000 

90,000 

Market Resources Portion

54,839 

44,647 

Tax Fees

10,113 

11,453 

Market Resources Portion

5,814 

2,751 

All Other Fees

295,455 

Market Resources Portion

7,280 


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


  1.1.*

Purchase Agreement, dated May 11, 2006, by and among Questar Market Resources, Inc., and named Underwriters. (Incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 11, 2006.)


  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.)




QUESTAR MARKET RESOURCES 2007 FORM 10-K

59




1

  4.1.*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.)


  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.*

Form of the Registrant’s 6.05% Notes due 2016. (Incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 11, 2006.)


  4.4.*

Form of Officers’ Certificate setting forth the terms of the 6.05% Notes. (Incorporated by reference to Exhibit 99.3 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 11, 2006.)


  4.5

Term Credit Agreement dated February 15, 2008, by and among the Company and Bank of America, N.A.


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.)


10.2.*

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.)


10.3.*

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.)


10.4.*

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.)


10.5.*

Fourth Amendment to Credit Agreement dated July 27, 2006, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 10.1 to the Company’s Quarterly Report on Form 10-Q for quarter ended June 30, 2006.)


10.6.*

Fifth Amendment to Credit Agreement dated July 25, 2007, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 10.1 to the Company’s Quarterly Report on Form 10-Q for quarter ended June 30, 2007.)


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.




QUESTAR MARKET RESOURCES 2007 FORM 10-K

60



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 27th day of February, 2008.


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/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



February 27, 2008

*By

/s/C. B. Stanley

           Date

C. B. Stanley, Attorney in Fact





QUESTAR MARKET RESOURCES 2007 FORM 10-K

61


Exhibits List


Exhibit No.

Description

  1.1.*

Purchase Agreement, dated May 11, 2006, by and among Questar Market Resources, Inc., and named Underwriters. (Incorporated by reference to Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 11, 2006.)


  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.)

1

  4.1.*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.)


  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.*

Form of the Registrant’s 6.05% Notes due 2016. (Incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 11, 2006.)


  4.4.*

Form of Officers’ Certificate setting forth the terms of the 6.05% Notes. (Incorporated by reference to Exhibit 99.3 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 11, 2006.)


  4.5

Term Credit Agreement dated February 15, 2008, by and among the Company and Bank of America, N.A.


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.)


10.2.*

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.)


10.3.*

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.)


10.4.*

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.)


10.5.*

Fourth Amendment to Credit Agreement dated July 27, 2006, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 10.1 to the Company’s Quarterly Report on Form 10-Q for quarter ended June 30, 2006.)


10.6.*

Fifth Amendment to Credit Agreement dated July 25, 2007, by and among Questar Market Resources, Inc., Bank of America, N.A. and other lenders. (Exhibit No. 10.1 to the Company’s Quarterly Report on Form 10-Q for quarter ended June 30, 2007.)





QUESTAR MARKET RESOURCES 2007 FORM 10-K

62


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.







QUESTAR MARKET RESOURCES 2007 FORM 10-K

63


Exhibit 4

EXECUTION VERSION


Exhibit 4.5



TERM LOAN CREDIT AGREEMENT

Dated as of February 15, 2008

among

QUESTAR MARKET RESOURCES, INC.,

as the Borrower,


BANK OF AMERICA, N.A.,

as Administrative Agent

and

The Lenders Party Hereto

BANC OF AMERICA SECURITIES LLC,

as

Sole Lead Arranger and Sole Book Manager






TABLE OF CONTENTS

Section

Page

Article I. DEFINITIONS AND ACCOUNTING TERMS

1

1.01

Defined Terms

1

1.02

Other Interpretive Provisions

14

1.03

Accounting Terms.

14

1.04

Rounding

15

1.05

References to Agreements and Laws

15

1.06

Times of Day

15

Article II. THE COMMITMENTS AND BORROWINGS

15

2.01

Loans

15

2.02

Borrowings, Conversions and Continuations of Loans.

15

2.03

Reserved.

17

2.04

Prepayments.

17

2.05

Termination or Reduction of Commitments

18

2.06

Repayment of Loans

19

2.07

Interest.

19

2.08

Fees

19

2.09

Computation of Interest and Fees

20

2.10

Evidence of Debt.

20

2.11

Payments Generally.

21

2.12

Sharing of Payments

22

Article III. TAXES, YIELD PROTECTION AND ILLEGALITY

22

3.01

Taxes.

22

3.02

Illegality

25

3.03

Inability to Determine Rates

26

3.04

Increased Cost and Reduced Return; Capital Adequacy; Reserves on Eurodollar Rate Loans.

26

3.05

Compensation for Losses

27

3.06

Matters Applicable to all Requests for Compensation.

27

3.07

Survival

27

Article IV. CONDITIONS PRECEDENT TO EFFECTIVENESS AND BORROWINGS

27

4.01

Conditions to Effectiveness of this Agreement

27

4.02

Conditions to Initial Loans

29

4.03

Conditions to Each Loan

29

4.04

Additional Condition to Loans for the Elm Grove Field Acquisition

29

Article V. REPRESENTATIONS AND WARRANTIES

29

5.01

No Default

29

5.02

Organization and Good Standing

29

5.03

Authorization

30

5.04

No Conflicts or Consents

30

5.05

Enforceable Obligations

30

5.06

Audited Financial Statements.

30

5.07

Other Obligations and Restrictions

31

5.08

Full Disclosure

31

5.09

Litigation

31

5.10

Labor Disputes and Acts of God

31

5.11

ERISA Plans and Liabilities

31

5.12

Environmental and Other Laws

31



H-712479.11




5.13

Borrower’s Subsidiaries

32

5.14

Title to Properties; Licenses

32

5.15

Government Regulation.

32

5.16

Solvency

33

5.17

Representations by the Borrower relating to Elm Grove Field Acquisition

33

Article VI. AFFIRMATIVE COVENANTS OF BORROWER

34

6.01

Payment and Performance

34

6.02

Books, Financial Statements and Reports

34

6.03

Other Information and Inspections

36

6.04

Notice of Material Events and Change of Address

36

6.05

Maintenance of Properties

37

6.06

Maintenance of Existence and Qualifications

37

6.07

Payment of Trade Liabilities, Taxes, etc.

37

6.08

Insurance

37

6.09

Performance on Borrower’s Behalf

37

6.10

Interest

37

6.11

Compliance with Agreements and Law

37

6.12

Environmental Matters.

37

6.13

Evidence of Compliance

38

6.14

Use of Proceeds

38

6.15

Subordination of Intercompany Indebtedness

38

Article VII. NEGATIVE COVENANTS OF BORROWER

38

7.01

Indebtedness

38

7.02

Limitation on Liens

39

7.03

Limitation on Investments and New Businesses

39

7.04

Limitation on Mergers

40

7.05

Limitation on Issuance of Securities by Subsidiaries of Borrower

40

7.06

Transactions with Affiliates

40

7.07

Prohibited Contracts

40

7.08

ERISA

40

7.09

Limitation on Sales of Property

40

7.10

Swap Contracts

41

7.11

Consolidated Funded Debt to Capitalization Ratio

41

Article VIII. EVENTS OF DEFAULT AND REMEDIES

41

8.01

Events of Default

41

8.02

Remedies upon Event of Default

43

8.03

Application of Funds

44

Article IX. ADMINISTRATIVE AGENT

44

9.01

Appointment and Authority.

44

9.02

Rights as a Lender

44

9.03

Exculpatory Provisions

45

9.04

Reliance by Administrative Agent.

45

9.05

Delegation of Duties

46

9.06

Resignation of Administrative Agent

46

9.07

Non-Reliance on Administrative Agent and Other Lenders

46

9.08

Administrative Agent May File Proofs of Claim

47

9.09

Other Agents; Arrangers and Managers

47

Article X. MISCELLANEOUS

47

10.01

Amendments, Etc

47

10.02

Notices; Effectiveness; Electronic Communications.

48



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10.03

No Waiver; Cumulative Remedies; Enforcement

50

10.04

Expenses; Indemnity; Damage Waiver.

50

10.05

Intentionally Left Blank.

52

10.06

Payments Set Aside

52

10.07

Successors and Assigns.

52

10.08

Confidentiality

55

10.09

Set-off

56

10.10

Interest Rate Limitation

56

10.11

Counterparts

56

10.12

Integration

56

10.13

Survival of Representations and Warranties

57

10.14

Severability

57

10.15

Replacement of Lenders

57

10.16

Governing Law.

57

10.17

Waiver of Right to Trial by Jury

58

10.18

No Advisory or Fiduciary Responsibility

58

10.19

Electronic Execution of Assignments and Certain Other Documents

58

10.20

USA PATRIOT Act Notice

59

10.21

Time of the Essence

59

10.22

ENTIRE AGREEMENT

59


SCHEDULES

SCHEDULE  2.01

Commitments and Pro Rata Shares

SCHEDULE  5.07

Obligations and Restrictions

SCHEDULE  5.10

Labor Disputes and Acts of God

SCHEDULE  5.11

ERISA Matters

SCHEDULE  5.12

Environmental Matters

SCHEDULE  5.13

Subsidiaries

SCHEDULE  5.17

Elm Grove Field Acquisition Agreements

SCHEDULE  10.02

Administrative Agent’s Office, Certain Addresses for Notices


EXHIBITS

EXHIBIT A:

Form of Loan Notice

EXHIBIT B:

Form of Note

EXHIBIT C:

Form of Compliance Certificate

EXHIBIT D:

Assignment and Assumption

EXHIBIT E:

Opinion Matters

EXHIBIT F:

Form of Subordination Agreement



H-712479.11




TERM LOAN CREDIT AGREEMENT

This TERM LOAN CREDIT AGREEMENT (this “Agreement”) is entered into as of February 15, 2008, among QUESTAR MARKET RESOURCES, INC., a Utah corporation (the “Borrower”), each lender from time to time party hereto (collectively, the “Lenders” and individually, a “Lender”), and BANK OF AMERICA, N.A., as Administrative Agent.

The Borrower has requested that the Lenders provide a term loan credit facility, and the Lenders are willing to do so on the terms and conditions set forth herein.

In consideration of the mutual covenants and agreements herein contained, the parties hereto covenant and agree as follows:

ARTICLE I.
DEFINITIONS AND ACCOUNTING TERMS

1.01

Defined Terms

.  As used in this Agreement, the following terms shall have the meanings set forth below:

Acquired Debt” means, with respect to any specified Person, (i) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Subsidiary of such specified Person, including, without limitation, Indebtedness incurred in connection with, or in contemplation of, such other Person merging with or into or becoming a Subsidiary of such specified Person, and (ii) Indebtedness secured by a Lien encumbering any assets acquired by such specified Person, and any refinancing of the foregoing indebtedness on similar terms, taking into account current market conditions.

Acquisition” means the Elm Grove Field Acquisition and other acquisitions by the Borrower or one or more Subsidiaries of the Borrower of oil and gas properties located in the United States, either pursuant to an acquisition of assets or of Equity Interests in Persons owning such properties.

Administrative Agent” means Bank of America in its capacity as administrative agent under any of the Loan Documents, or any successor administrative agent.

Administrative Agent’s Office” means the Administrative Agent’s address and, as appropriate, account as set forth on Schedule 10.02, or such other address or account as the Administrative Agent may from time to time notify the Borrower and the Lenders.

Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Administrative Agent.

Affiliate” means, as to any Person, each other Person that directly or indirectly (through one or more intermediaries or otherwise) controls, is controlled by, or is under common control with, such Person. A Person shall be deemed to be “controlled by” any other Person if such other Person possesses, directly or indirectly, power

(a)

to vote 20% or more of the securities (on a fully diluted basis) having ordinary voting power for the election of directors or managing general partners; or



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(b)

to direct or cause the direction of the management and policies of such Person whether by contract or otherwise.

Aggregate Commitments” means the Commitments of all the Lenders in an amount not to exceed $700,000,000.

Agreement” means this Agreement.

“Applicable Rate” means, from time to time, the following percentages per annum, based upon the Debt Rating as set forth below:

Applicable Rate

Pricing Level

Debt Rating


Applicable Margin

for LIBOR Loans from the Closing Date to May 14, 2008


Applicable Margin

for LIBOR Loans from  and after

 May 15



Commitment

Fee

1

≥A- / A3

0.40%

0.65%

0.08%

2

BBB+ / Baa1

0.45%

0.70%

0.10%

3

BBB / Baa2

0.55%

0.80%

0.11%

4

BBB- / Baa3

0.70%

0.95%

0.14%

5

≤BB+ / Ba1

1.00%

1.25%

0.16%


Debt Rating” means, as of any date of determination, the rating as determined by either S&P or Moody’s (collectively, the “Debt Ratings”) of the Borrower’s non-credit-enhanced, senior unsecured long-term debt; provided that if a Debt Rating is issued by each of the foregoing rating agencies, then the lower of such Debt Ratings shall apply (with the Debt Rating for Pricing Level 1 being the highest and the Debt Rating for Pricing Level 5 being the lowest), unless (i) there is a split in Debt Ratings of more than one level, in which case the Pricing Level that is one level higher than the Pricing Level of the lower Debt Rating shall apply, (ii) there is a multiple level split in Debt Ratings, in which case the Pricing Level that is one level lower than the higher of the two shall apply, or (iii) there is no Debt Rating, in which case Pricing Level 5 shall apply.

Initially, the Applicable Rate shall be determined based upon the Debt Rating specified in the certificate delivered pursuant to Section 4.01(b). Thereafter, each change in the Applicable Rate resulting from a publicly announced change in the Debt Rating shall be effective, in the case of an upgrade, during the period commencing on the date of delivery by the Borrower to the Administrative Agent of notice thereof pursuant to Section 6.04(h) and ending on the date immediately preceding the effective date of the next such change and, in the case of a downgrade, during the period commencing on the date of the public announcement thereof and ending on the date immediately preceding the effective date of the next such change.

Arranger” means Banc of America Securities LLC, in its capacity as sole lead arranger and sole book manager.

Asset Sale Threshold” means $200,000,000.

Assignee Group” means two or more Eligible Assignees that are Affiliates of one another or two or more Approved Funds managed by the same investment advisor.



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Assignment and Assumption” means an Assignment and Assumption substantially in the form of Exhibit D.

Attorney Costs” means and includes all reasonable fees, expenses and disbursements of any law firm or other external counsel.

Attributable Indebtedness” means, on any date, (a) in respect of any capital lease of any Person, the capitalized amount thereof that would appear on a balance sheet of such Person prepared as of such date in accordance with GAAP, and (b) in respect of any Synthetic Lease Obligation, the capitalized amount of the remaining lease payments under the relevant lease that would appear on a balance sheet of such Person prepared as of such date in accordance with GAAP if such lease were accounted for as a capital lease.

Audited Financial Statements” means the audited consolidated balance sheet of the Borrower and its Subsidiaries for the fiscal year ended December 31, 2006, and the related consolidated statements of income or operations, shareholders’ equity and cash flows for such fiscal year of the Borrower and its Subsidiaries, including the notes thereto.

Availability Period” means the period from and including the Closing Date to the earlier of (a) the date the full amount of all the Commitments has been drawn, (b) the Maturity Date, and (b) the date of termination of the Commitment of each Lender to make Loans pursuant to Section 8.02.

Bank of America” means Bank of America, N.A. and its successors.

Base Rate” means for any day a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus 1/2 of 1% and (b) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate.” The “prime rate” is a rate set by Bank of America based upon various factors including Bank of America’s costs and desired return, general economic conditions and other factors, and is used as a reference point for pricing some loans, which may be priced at, above, or below such announced rate. Any change in such rate announced by Bank of America shall take effect at the opening of business on the day specified in the public announcement of such change.

Base Rate Loan” means a Loan that bears interest based on the Base Rate.

Borrower” has the meaning specified in the introductory paragraph hereto.

Borrowing” means a borrowing consisting of simultaneous Loans of the same Type and, in the case of Eurodollar Rate Loans, having the same Interest Period made by each of the Lenders pursuant to Section 2.01.

Business Day” means any day other than a Saturday, Sunday or other day on which commercial banks are authorized to close under the Laws of, or are in fact closed in, the state where the Administrative Agent’s Office is located and, if such day relates to any Eurodollar Rate Loan, means any such day on which dealings in Dollar deposits are conducted by and between banks in the London interbank eurodollar market.

Change of Control” means:

(a)

Questar Corporation ceases to own 100% of the equity interests of the Borrower;  provided, however, that the Borrower may issue additional equity interests provided that (x) after such issuance Questar Corporation owns not less than 75% of the equity interests of the



H-712479.11

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Borrower and (y) such issuance does not result in the Borrower losing investment grade rating status (for purposes of this clause, investment grade rating status means the Borrower has Debt Ratings of not lower than BBB- from S&P and Baa3 from Moody’s);

(b)

during any period of 12 consecutive months, a majority of the members of the board of directors of the Borrower cease to be composed of individuals (i) who were members of that board on the first day of such period, (ii) whose election or nomination to that board or equivalent governing body was approved by individuals referred to in clause (i) above constituting at the time of such election or nomination at least a majority of that board or (iii) whose election or nomination to that board was approved by individuals referred to in clauses (i) and (ii) above constituting at the time of such election or nomination at least a majority of that board (excluding, in the case of both clause (ii) and clause (iii), any individual whose initial nomination for, or assumption of office as, a member of that board occurs as a result of an actual or threatened solicitation of proxi es or consents for the election or removal of one or more directors by any person or group other than a solicitation for the election of one or more directors by or on behalf of the board of directors.

In the event that the Borrower issues debt instruments that are convertible into equity of the Borrower, compliance with the 75% requirement set forth in clause (a) above shall be calculated at the time such convertible instruments are issued by assuming that, for purposes of such calculation, all of such debt instruments have been converted into equity.

Closing Date” means February 15, 2008, which is the first date all the conditions precedent in Section 4.01 are satisfied or waived in accordance with Section 10.01.

Code” means the Internal Revenue Code of 1986.

Commitment” means, as to each Lender, its obligation to make Loans to the Borrower pursuant to Section 2.01, in an aggregate principal amount at any one time outstanding not to exceed the amount set forth opposite such Lender’s name on Schedule 2.01 or in the Assignment and Assumption pursuant to which such Lender becomes a party hereto, as applicable, as such amount may be adjusted from time to time in accordance with this Agreement.

Compliance Certificate” means a certificate substantially in the form of Exhibit C.

Consolidated Funded Debt” means the aggregate of the Indebtedness of the Borrower and its Subsidiaries described in clauses (a), (b), (d), (e), (f) and (g) of the definition of Indebtedness in Section 1.01, on a consolidated basis after elimination of intercompany items.

Consolidated Funded Debt to Capitalization Ratio” means, at the time of determination, the ratio of (a) Consolidated Funded Debt to (b) the sum of Consolidated Funded Debt plus Shareholder’s Equity.

Contractual Obligation” means, as to any Person, any provision of any security issued by such Person or of any agreement, instrument or other undertaking to which such Person is a party or by which it or any of its property is bound.  “

Debt Rating” has the meaning specified in the definition of “Applicable Rate.”

Debtor Relief Laws” means the Bankruptcy Code of the United States, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement,



H-712479.11

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receivership, insolvency, reorganization, or similar debtor relief Laws of the United States or other applicable jurisdictions from time to time in effect and affecting the rights of creditors generally.

Default” means any event or condition that constitutes an Event of Default or that, with the giving of any notice, the passage of time, or both, would be an Event of Default.

Default Rate” means when used with respect to Obligations, an interest rate equal to (i) the Base Rate plus (ii) 1% per annum; provided, however, that with respect to a Eurodollar Rate Loan, the Default Rate shall be an interest rate equal to the interest rate (including the Applicable Rate) otherwise applicable to such Loan plus 1% per annum, in each case to the fullest extent permitted by applicable Laws.

Defaulting Lender” means any Lender that (a) has failed to fund any portion of the Loans required to be funded by it hereunder within one Business Day of the date required to be funded by it hereunder, (b) has otherwise failed to pay over to the Administrative Agent or any other Lender any other amount required to be paid by it hereunder within one Business Day of the date when due, unless the subject of a good faith dispute, or (c) has been deemed insolvent or become the subject of a bankruptcy or insolvency proceeding.

Disposition” or “Dispose” means the sale, transfer, license, lease or other disposition (including any sale and leaseback transaction) of any property by any Person, including any sale, assignment, transfer or other disposal, with or without recourse, of any notes or accounts receivable or any rights and claims associated therewith.

Dollar” and “$” mean lawful money of the United States.

Eligible Assignee” has the meaning specified in Section 10.07(g).

Elm Grove Field Acquisition” means the acquisition by the Borrower or a Subsidiary of the Borrower of two natural gas development properties near the Borrower’s Elm Grove Field operations pursuant to the Elm Grove Field Acquisition Agreements.

Elm Grove Field Acquisition Agreements” means those certain agreements described in Schedule 5.17.


Environmental Laws” means any and all Federal, state, local, and foreign statutes, laws, regulations, ordinances, rules, judgments, orders, decrees, permits, concessions, grants, franchises, licenses, agreements or governmental restrictions relating to pollution and the protection of the environment or the release of any materials into the environment, including those related to hazardous substances or wastes, air emissions and discharges to waste or public systems.

Environmental Liability” means any liability, contingent or otherwise (including any liability for damages, costs of environmental remediation, fines, penalties or indemnities), of the Borrower, any other Loan Party or any of their respective Subsidiaries directly or indirectly resulting from or based upon (a) violation of any Environmental Law, (b) the generation, use, handling, transportation, storage, treatment or disposal of any Hazardous Materials, (c) exposure to any Hazardous Materials, (d) the release or threatened release of any Hazardous Materials into the environment or (e) any contract, agreement or other consensual arrangement pursuant to which liability is assumed or imposed with respect to any of the foregoing.

Equity Interests”, “equity interests” and “equity securities” means, with respect to any Person, all of the shares of capital stock of (or other ownership or profit interests in) such Person, all of the



H-712479.11

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warrants, options or other rights for the purchase or acquisition from such Person of shares of capital stock of (or other ownership or profit interests in) such Person, all of the securities convertible into or exchangeable for shares of capital stock of (or other ownership or profit interests in) such Person or warrants, rights or options for the purchase or acquisition from such Person of such shares (or such other interests), and all of the other ownership or profit interests in such Person (including partnership, member or trust interests therein), whether voting or non-voting, and whether or not such shares, warrants, options, rights or other interests are outstanding on any date of determination.  The term Equity Interests shall also include other securities or instruments that have both debt and equity features.

ERISA” means the Employee Retirement Income Security Act of 1974.

ERISA Affiliate” means any trade or business (whether or not incorporated) under common control with the Borrower within the meaning of Section 414(b) or (c) of the Code (and Sections 414(m) and (o) of the Code for purposes of provisions relating to Section 412 of the Code).

ERISA Event” means (a) a Reportable Event with respect to a Pension Plan; (b) a withdrawal by the Borrower or any ERISA Affiliate from a Pension Plan subject to Section 4063 of ERISA during a plan year in which it was a substantial employer (as defined in Section 4001(a)(2) of ERISA) or a cessation of operations that is treated as such a withdrawal under Section 4062(e) of ERISA; (c) a complete or partial withdrawal by the Borrower or any ERISA Affiliate from a Multiemployer Plan or notification that a Multiemployer Plan is in reorganization; (d) the filing of a notice of intent to terminate, the treatment of a Plan amendment as a termination under Sections 4041 or 4041A of ERISA, or the commencement of proceedings by the PBGC to terminate a Pension Plan or Multiemployer Plan; (e) an event or condition which constitutes grounds under Section 4042 of ERISA for the termi nation of, or the appointment of a trustee to administer, any Pension Plan or Multiemployer Plan; or (f) the imposition of any liability under Title IV of ERISA, other than for PBGC premiums due but not delinquent under Section 4007 of ERISA, upon the Borrower or any ERISA Affiliate.

Eurodollar Rate” means, for any Interest Period with respect to a Eurodollar Rate Loan, the rate per annum equal to the British Bankers Association LIBOR Rate (“BBA LIBOR”), as published by Reuters (or other commercially available source providing quotations of BBA LIBOR as designated by the Administrative Agent from time to time) at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period, for Dollar deposits (for delivery on the first day of such Interest Period) with a term equivalent to such Interest Period.  If such rate is not available at such time for any reason, then the “Eurodollar Rate” for such Interest Period shall be the rate per annum determined by the Administrative Agent to be the rate at which deposits in Dollars for delivery on the first day of such Interest Period in s ame day funds in the approximate amount of the Eurodollar Rate Loan being made, continued or converted by Bank of America and with a term equivalent to such Interest Period would be offered by Bank of America’s London Branch to major banks in the London interbank eurodollar market at their request at approximately 11:00 a.m. (London time) two Business Days prior to the commencement of such Interest Period.

Eurodollar Rate Loan” means a Loan that bears interest at a rate based on the Eurodollar Rate.

Event of Default” has the meaning specified in Section 8.01.

Existing Credit Agreement” means that certain Credit Agreement dated as of March 19, 2004, by and among the Borrower, Bank of America, as administrative agent, and the lenders party thereto, as amended.



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Federal Funds Rate” means, for any day, the rate per annum equal to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers on such day, as published by the Federal Reserve Bank of New York on the Business Day next succeeding such day; provided that (a) if such day is not a Business Day, the Federal Funds Rate for such day shall be such rate on such transactions on the next preceding Business Day as so published on the next succeeding Business Day, and (b) if no such rate is so published on such next succeeding Business Day, the Federal Funds Rate for such day shall be the average rate (rounded upward, if necessary, to a whole multiple of 1/100 of 1%) charged to Bank of America on such day on such transactions as determined by the Administrative Agent.

Fee Letter” means the letter agreement, dated January 25, 2008, among the Borrower, the Administrative Agent and the Arranger.

Foreign Lender” means any Lender that is organized under the Laws of a jurisdiction other than that in which the Borrower is resident for tax purposes.  For purposes of this definition, the United States, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.

FRB” means the Board of Governors of the Federal Reserve System of the United States.

Fund” has the meaning set forth in Section 10.07(g).

GAAP” means generally accepted accounting principles in the United States set forth in the opinions and pronouncements of the Accounting Principles Board and the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or Such other principles as may be approved by a significant segment of the accounting profession in the United States, that are applicable to the circumstances as of the date of determination, consistently applied.

Governmental Authority” means any nation or government, any state or other political subdivision thereof, any agency, authority, instrumentality, regulatory body, court, administrative tribunal, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government.

Guarantee” means, as to any Person, (a) any obligation, contingent or otherwise, of such Person guaranteeing or having the economic effect of guaranteeing any Indebtedness or other obligation payable or performable by another Person (the “primary obligor”) in any manner, whether directly or indirectly, and including any obligation of such Person, direct or indirect, (i) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or other obligation, (ii) to purchase or lease property, securities or services for the purpose of assuring the obligee in respect of such Indebtedness or other obligation of the payment or performance of such Indebtedness or other obligation, (iii) to maintain working capital, equity capital or any other financial statement condition or liquidity or level of income or cash flow of the primary obli gor so as to enable the primary obligor to pay such Indebtedness or other obligation, or (iv) entered into for the purpose of assuring in any other manner the obligee in respect of such Indebtedness or other obligation of the payment or performance thereof or to protect such obligee against loss in respect thereof (in whole or in part), or (b) any Lien on any assets of such Person securing any Indebtedness or other obligation of any other Person, whether or not such Indebtedness or other obligation is assumed by such Person. The amount of any Guarantee shall be deemed to be an amount equal to the stated or determinable amount of the related primary obligation, or portion thereof, in respect of which such Guarantee is made or, if not stated or determinable, the maximum reasonably anticipated liability in respect thereof as determined by the guaranteeing Person in good faith. The term “Guarantee” as a verb has a corresponding meaning.



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Hazardous Materials” means all explosive or radioactive substances or wastes and all hazardous or toxic substances, wastes or other pollutants, including petroleum or petroleum distillates, asbestos or asbestos-containing materials, polychlorinated biphenyls, radon gas, infectious or medical wastes and all other substances or wastes of any nature regulated pursuant to any Environmental Law.

Indebtedness” means, as to any Person at a particular time, without duplication, all of the following, whether or not included as indebtedness or liabilities in accordance with GAAP:

(a)

all obligations of such Person for borrowed money and all obligations of such Person evidenced by bonds, debentures, notes, loan agreements or other similar instruments;

(b)

all direct or contingent obligations of such Person arising under letters of credit (including standby and commercial), bankers’ acceptances, bank guaranties, surety bonds and similar instruments;.

(c)

net obligations of such Person under any Swap Contract;

(d)

all obligations of such Person to pay the deferred purchase price of property or services (other than trade accounts payable in the ordinary course of business);

(e)

indebtedness (excluding prepaid interest thereon) secured by a Lien on property owned or being purchased by such Person (including indebtedness arising under conditional sales or other title retention agreements), whether or not such indebtedness shall have been assumed by such Person or is limited in recourse;

(f)

capital leases and Synthetic Lease Obligations; and

(g)

all Guarantees of such Person in respect of any of the foregoing.

For all purposes hereof, the Indebtedness of any Person shall include the Indebtedness of any partnership or joint venture (other than a joint venture that is itself a corporation or limited liability company) in which such Person is a general partner or a joint venturer, unless such Indebtedness is expressly made non-recourse to such Person. The amount of any net obligation under any Swap Contract on any date shall be deemed to be the Swap Termination Value thereof as of such date. The amount of any capital lease or Synthetic Lease Obligation as of any date shall be deemed to be the amount of Attributable Indebtedness in respect thereof as of such date.

Indemnitees” has the meaning specified in Section 10.04(b).

Interest Payment Date” means, (a) as to any Loan other than a Base Rate Loan, the last day of each Interest Period applicable to such Loan and the Maturity Date; provided, however, that if any Interest Period for a Eurodollar Rate Loan exceeds three months, the respective dates that fall every three months after the beginning, of such Interest Period shall also be Interest Payment Dates; and (b) as to any Base Rate Loan, the last Business Day of each March, June, September and December and the Maturity Date.

Interest Period” means, as to each Eurodollar Rate Loan, the period commencing on the date such Eurodollar Rate Loan is disbursed or converted to or continued as a Eurodollar Rate Loan and ending on the date (a) one, two, three or six months thereafter, or (b) subject to availability with respect to all Lenders, one, two or three weeks thereafter, in any case as selected by the Borrower in its Loan Notice; provided that:



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(i)

any Interest Period that would otherwise end on a day that is not a Business Day shall be extended to the next succeeding Business Day unless such Business Day falls in another calendar month, in which case such Interest Period shall end on the next preceding Business Day;

(ii)

any Interest Period that begins on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period) shall end on the last Business Day of the calendar month at the end of such Interest Period; and

(iii)

no Interest Period shall extend beyond the Maturity Date.

Investment” means, as to any Person, any direct or indirect acquisition or investment by such Person, whether by means of (a) the purchase or other acquisition of capital stock or other securities of another Person, (b) a loan, advance or capital contribution to, Guarantee or assumption of debt of, or purchase or other acquisition of any other debt or equity participation or interest in, another Person, including any partnership or joint venture interest in such other Person, or (c) the purchase or other acquisition (in one transaction or a series of transactions) of assets of another Person that constitute a business unit. For purposes of covenant compliance, the amount of any Investment shall be the amount actually invested, without adjustment for subsequent increases or decreases in the value of such Investment.

Laws” means, collectively, all international, foreign, Federal, state and local statutes, treaties, rules, guidelines, regulations, ordinances, codes and administrative or judicial precedents or authorities, including the interpretation or administration thereof by any Governmental Authority charged with the enforcement, interpretation or administration thereof, and all applicable administrative orders, directed duties, requests, licenses, authorizations and permits of, and agreements with, any Governmental Authority, in each case whether or not having the force of law.

Lender” has the meaning specified in the introductory paragraph hereto.

Lending Office” means, as to any Lender, the office or offices of such Lender described as such in such Lender’s Administrative Questionnaire, or such other office or offices as a Lender may from time to time notify the Borrower and the Administrative Agent.

Lien” means any mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory or other), charge, or preference, priority or other security interest or preferential arrangement in the nature of a security interest of any kind or nature whatsoever (including any conditional sale or other title retention agreement, and any financing lease having substantially the same economic effect as any of the foregoing).

Loan” has the meaning specified in Section 2.01.

Loan Documents” means this Agreement, each Note, and the Fee Letter.

Loan Notice” means a written notice of (a) a Borrowing, (b) a conversion of Loans from one Type to the other, or (c) a continuation of Eurodollar Rate Loans, pursuant to Section 2.02(a), which shall be substantially in the form of Exhibit A.

Loan Parties” means, collectively, the Borrower and the Restricted Subsidiaries.



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Material Adverse Effect” means any event which would reasonably be expected to have a material and adverse effect upon (a) the Borrower’s consolidated financial condition, (b) the Borrower’s consolidated operations, properties or prospects, considered as a whole, (c) the Borrower’s ability to timely pay the Obligations, or (d) the enforceability of the material terms of any Loan Document.

Maturity Date” means August 15, 2008.

Moody’s” means Moody’s Investors Service, Inc. and any successor thereto.

Multiemployer Plan” means any employee benefit plan of the type described in Section 4001(a)(3) of ERISA, to which the Borrower or any ERISA Affiliate makes or is obligated to make contributions, or during the preceding five plan years, has made or been obligated to make contributions.

Net Cash Proceeds” means:

(a)

with respect to any incurrence or issuance of any Indebtedness, or the sale or issuance of any Equity Interests, all cash or cash equivalents received by the Borrower or any of its Subsidiaries after payment of all reasonable attorneys’, accountants’, consultants’ and financial advisors’ fees and usual and customary underwriting commissions, closing costs, and other reasonable expenses associated therewith; and

(b)

with respect to any Disposition, all cash or cash equivalents (including any cash received by way of deferred payment pursuant to a promissory note or otherwise, as and when received) received by the Borrower or any of its Subsidiaries in connection with and as consideration therefor, on or after the date of consummation of such transaction, after deduction of (i) income taxes payable in connection with or as a result of such transaction, and (ii) payment of all usual and customary brokerage commissions and all other reasonable fees and expenses related to such transaction (including, without limitation, reasonable attorneys’, accountants’, consultants’ and financial advisors’ fees, costs incurred in connection with environmental reviews and inspections, and closing costs incurred in connection with such transaction).

Notwithstanding the foregoing, “Net Cash Proceeds” shall exclude proceeds from the settlement of Swap Contracts at termination in the ordinary course of business.

Note” means a promissory note made by the Borrower in favor of a Lender evidencing Loans made by such Lender, substantially in the form of Exhibit B.

Obligations” means all advances to, and debts, liabilities, obligations, covenants and duties of, any Loan Party arising under any Loan Document or otherwise with respect to any Loan, whether such Obligations are direct or indirect (including those acquired by assumption), absolute or contingent, due or to become due, now existing or hereafter arising and including interest and fees that accrue after the commencement by or against any Loan Party or any Affiliate thereof of any proceeding under any Debtor Relief Laws naming such Person as the debtor in such proceeding, regardless of whether such interest and fees are allowed claims in such proceeding.

Organization Documents” means, (a) with respect to any corporation, the certificate or articles of incorporation and the bylaws (or equivalent or comparable constitutive documents with respect to any non-U.S. jurisdiction); (b) with respect to any limited liability company, the certificate or articles of formation or organization and operating agreement; and (c) with respect to any partnership, joint venture, trust or other form of business entity, the partnership, joint venture or other applicable agreement of formation or organization and any agreement, instrument, filing or notice with respect thereto filed in



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connection with its formation or organization with the applicable Governmental Authority in the jurisdiction of its formation or organization and, if applicable, any certificate or articles of formation or organization of such entity.

Other Taxes” means all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies arising from any payment made hereunder or under any other Loan Document or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement or any other Loan Document.

Outstanding Amount” means, on any date, the aggregate outstanding principal amount of the Loans after giving effect to any borrowings and prepayments or repayments thereof, as the case may be, occurring on such date.

Participant” has the meaning specified in Section 10.07(d).

PBGC” means the Pension Benefit Guaranty Corporation.

Pension Plan” means any “employee pension benefit plan” (as such term is defined in Section 3(2) of ERISA), other than a Multiemployer Plan, that is subject to Title IV of ERISA and is sponsored or maintained by the Borrower or any ERISA Affiliate or to which the Borrower or any ERISA Affiliate contributes or has an obligation to contribute, or in the case of a multiple employer or other plan described in Section 4064(a) of ERISA, has made contributions at any time during the immediately preceding five plan years.

Permitted Liens” means:

(a)

operators’ liens under customary operating agreements, liens arising under gas transportation and purchase agreements on the gas being transported or processed which secure related gas transportation and processing fees only, statutory Liens for taxes, statutory mechanics’ and materialmen’s Liens, and other similar statutory Liens, provided such Liens secure only indebtedness, liabilities and obligations which are not delinquent or which are being contested as provided in Section 6.07 of this Agreement;

(b)

Liens on any oil and gas properties which neither have developed reserves (producing or non-producing) properly attributable thereto nor are otherwise held under lease by production of other reserves;

(c)

Liens on the Loan Parties’ office facilities;

(d)

Liens on property securing non-recourse debt permitted under Section 7.01(f) of this Agreement which is acquired with proceeds or developed with proceeds of the non-recourse debt; and

(e)

Liens to secure the Obligations;

provided that nothing in this definition shall in and of itself constitute or be deemed to constitute an agreement or acknowledgment by the Administrative Agent or any Lender that the Indebtedness subject to or secured by any such Permitted Lien ranks (apart from the effect of any Lien included in or inherent in any such Permitted Liens) in priority to the Obligations.



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Person” means any natural person, corporation, limited liability company, trust, joint venture, association, company, partnership, Governmental Authority or other entity.

Plan” means any “employee benefit plan” (as such term is defined in Section 3(3) of ERISA) established by the Borrower or, with respect to any such plan that is subject to Section 412 of the Code or Title IV of ERISA, any ERISA Affiliate.

Pro Rata Share” means, with respect to each Lender: (a) on any date of determination during the Availability Period, a fraction (expressed as a percentage, carried out to the ninth decimal place), the numerator of which is the Commitment of such Lender at such time and the denominator of which is the Aggregate Commitments at such time; provided, that if the Commitments of the Lenders to make Loans have terminated whether pursuant to Section 8.02 or otherwise, then the Pro Rata Share of each Lender shall be determined based on the Pro Rata Share of such Lender immediately prior to such termination; (b) on any date of determination occurring after the Availability Period, a fraction (expressed as a percentage, carried out to the ninth decimal place), the numerator of which is the aggregate principal amount of such Lender’s Loans at such time and the denominat or of which is the aggregate principal amount of all Loans at such time.  The initial Pro Rata Share of each Lender is set forth opposite the name of such Lender on Schedule 2.01 or in the Assignment and Assumption pursuant to which such Lender becomes a party hereto, as applicable.

Register” has the meaning specified in Section10.07(c).

Related Parties” means, with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents, trustees and advisors of such Person and of such Person’s Affiliates.

Replacement Revolving Credit Facility” means a revolving credit facility entered into after the date of this Agreement by and among the Borrower and one or more financial institutions, as lenders, that increases, amends, replaces and/or refinances the credit facility under the Existing Credit Agreement.

Reportable Event” means any of the events set forth in Section 4043(c) of ERISA, other than events for which the 30 day notice period has been waived.

Required Lenders” means (a) during the Availability Period, Lenders having more than fifty percent (50%) of the Aggregate Commitments; and (b) after the Availability Period, Lenders holding more than fifty percent (50%) of the Outstanding Amount.

Responsible Officer” means the chairman of the board, chief executive officer, president or chief financial officer of the Borrower. Any document delivered hereunder that is signed by a Responsible Officer of a Loan Party shall be conclusively presumed to have been authorized by all necessary corporate, partnership and/or other action on the part of such Loan Party and such Responsible Officer shall be conclusively presumed to have acted on behalf of such Loan Party.

Restricted Payment” means any dividend or other distribution (whether in cash, securities or other property) with respect to any capital stock or other equity interest of the Borrower or any Subsidiary, or any payment (whether in cash, securities or other property), including any sinking fund or similar deposit, on account of the purchase, redemption, retirement, acquisition, cancellation or termination of any such capital stock or other equity interest or of any option, warrant or other right to acquire any such capital stock or other equity interest.



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Restricted Subsidiary” means any Subsidiary of the Borrower that is not an Unrestricted Subsidiary.

Revolving Closing Date Prepayment” has the meaning set forth in Section 2.04(b)(i)(B).

S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc. and any successor thereto.

SEC” means the Securities and Exchange Commission, or any Governmental Authority succeeding to any of its principal functions.

Shareholder’s Equity” means the remainder of (i) the Borrower’s assets on a consolidated basis minus (ii) the sum of (x) the Borrower’s liabilities on a consolidated basis (such assets and liabilities to be calculated excluding unrealized noncash gains or losses resulting from “mark-to-market” adjustments pursuant to FAS 133) plus (y) all treasury stock of the Borrower and its Subsidiaries.

Subsidiary” of a Person means a corporation, partnership, joint venture, limited liability company or other business entity of which a majority of the shares of securities or other interests having ordinary voting power for the election of directors or other governing body (other than securities or interests having such power only by reason of the happening of a contingency) are at the time beneficially owned, or the management of which is otherwise controlled, directly, or indirectly through one or more intermediaries, or both, by such Person. Unless otherwise specified, all references herein to a “Subsidiary” or to “Subsidiaries” shall refer to a Subsidiary or Subsidiaries of the Borrower.

Swap Contract” means (a) any and all rate swap transactions, basis swaps, credit derivative transactions, forward rate transactions, commodity swaps, commodity options, forward commodity contracts, equity or equity index swaps or options, bond or bond price or bond index swaps or options or forward bond or forward bond price or forward bond index transactions, interest rate options, forward foreign exchange transactions, cap transactions, floor transactions, collar transactions, currency swap transactions, cross-currency rate swap transactions, currency options, spot contracts, or any other similar transactions or any combination of any of the foregoing (including any options to enter into any of the foregoing), whether or not any such transaction is governed by or subject to any master agreement, and (b) any and all transactions of any kind, and the related confirmati ons, which are subject to the terms and conditions of, or governed by, any form of master agreement published by the International Swaps and Derivatives Association, Inc., any International Foreign Exchange Master Agreement, or any other master agreement (any such master agreement, together with any related schedules, a “Master Agreement”), including any such obligations or liabilities under any Master Agreement.

Swap Termination Value” means, in respect of any one or more Swap Contracts, after taking into account the effect of any legally enforceable netting agreement relating to such Swap Contracts, (a) for any date on or after the date such Swap Contracts have been closed out and termination value(s) determined in accordance therewith, such termination value(s), and (b) for any date prior to the date referenced in clause (a), the amount(s) determined as the mark-to-market value(s) for such Swap Contracts, as determined based upon one or more mid-market or other readily available quotations provided by any recognized dealer in such Swap Contracts (which may include a Lender or any Affiliate of a Lender).

Synthetic Lease Obligation” means the monetary obligation of a Person under (a) a so-called synthetic, off-balance sheet or tax retention lease, or (b) an agreement for the use or possession of property creating obligations that do not appear on the balance sheet of such Person but which, upon the



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insolvency or bankruptcy of such Person, would be characterized as the indebtedness of such Person (without regard to accounting treatment).

Taxes” means all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

Type” means, with respect to a Loan, its character as a Base Rate Loan or a Eurodollar Rate Loan.

United States” and “U.S.” mean the United States of America.

Unrestricted Subsidiary” means any Person in which the Borrower does not presently own an interest (directly or indirectly) which hereafter becomes a Subsidiary of the Borrower and which, within 90 days thereafter, is designated as an Unrestricted Subsidiary by the Borrower to Administrative Agent, provided that the Borrower may not designate as an Unrestricted Subsidiary any Subsidiary in which it has made an Investment of more than $25,000,000 (directly or indirectly) by any means other than newly issued stock or treasury stock of the Borrower, which may be used to make an Investment in Unrestricted Subsidiaries without limit and provided further that in the event the book value of the assets of any Unrestricted Subsidiary at any time exceeds $25,000,000, such Subsidiary shall cease to be an Unrestricted Subsidiary and shall automatically become a Restr icted Subsidiary. No Unrestricted Subsidiary may, directly or indirectly, make any Investment in any Loan Party. No Loan Party may guaranty or otherwise become liable in respect of any Indebtedness or other obligations of, grant any Lien on any of its property to secure any Indebtedness of or other obligation of, or provide any other form of credit support to, any Unrestricted Subsidiary.

1.02

Other Interpretive Provisions

.  With reference to this Agreement and each other Loan Document, unless otherwise specified herein or in such other Loan Document:

(a)

The meanings of defined terms are equally applicable to the singular and plural forms of the defined terms.

(b)

1)

The words “hereto,” “hereof” and “hereunder” and words of similar import when used in any Loan Document shall refer to such Loan Document as a whole and not to any particular provision thereof.

2)

Article, Section, Exhibit and Schedule references are to the Loan Document in which such reference appears.

3)

The term “including” is by way of example and not limitation.

4)

The term “documents” includes any and all instruments, documents, agreements, certificates, notices, reports, financial statements and other writings, however evidenced, whether in physical or electronic form.

(c)

In the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including;” the words “to” and “until” each mean “to but excluding;” and the word “through” means “to and including.”



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(d)

Section headings herein and in the other Loan Documents are included for convenience of reference only and shall not affect the interpretation of this Agreement or any other Loan Document.

1.03

Accounting Terms.

(a)

All accounting terms not specifically or completely defined herein shall be construed in conformity with, and all financial data (including financial ratios and other financial calculations) required to be submitted pursuant to this Agreement shall be prepared in conformity with, GAAP applied on a consistent basis, as in effect from time to time, applied in a manner consistent with that used in preparing the Audited Financial Statements, except as otherwise specifically prescribed herein.

(b)

If at any time any change in GAAP would affect the computation of any financial ratio or requirement set forth in any Loan Document, and either the Borrower or the Required Lenders shall so request, the Administrative Agent, the Lenders and the Borrower shall negotiate in good faith to amend such ratio or requirement to preserve the original intent thereof in light of such change in GAAP (subject to the approval of the Required Lenders); provided that, until so amended, (i) such ratio or requirement shall continue to be computed in accordance with GAAP prior to such change therein and (ii) the Borrower shall provide to the Administrative Agent and the Lenders financial statements and other documents required under this Agreement or as reasonably requested hereunder setting forth a reconciliation between calculations of such ratio or requirement made before and after giving effect to such change in GAAP.

1.04

Rounding

.  Any financial ratios required to be maintained by the Borrower pursuant to this Agreement shall be calculated by dividing the appropriate component by the other component, carrying the result to one place more than the number of places by which such ratio is expressed herein and rounding the result up or down to the nearest number (with a rounding-up if there is no nearest number).

1.05

References to Agreements and Laws

.  Unless otherwise expressly provided herein, (a) references to Organization Documents, agreements (including the Loan Documents) and other contractual instruments shall be deemed to include all subsequent amendments, restatements, extensions, supplements and other modifications thereto, but only to the extent that such amendments, restatements, extensions, supplements and other modifications are not prohibited by any Loan Document; and (b) references to any Law shall include all statutory and regulatory provisions consolidating, amending, replacing, supplementing or interpreting such Law.

1.06

Times of Day

.  Unless otherwise specified, all references herein to times of day shall be references to Central time (daylight or standard, as applicable).

ARTICLE II.
THE COMMITMENTS AND BORROWINGS

2.01

Loans

.  Subject to the terms and conditions set forth herein, each Lender severally agrees to make loans (each such loan, a “Loan”) in Dollars to the Borrower from time to time, on any Business Day during the Availability Period, in an aggregate amount not to exceed at any time outstanding the amount of such



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Lender’s Commitment; provided, however, that after giving effect to any Borrowing, (i) the Outstanding Amount of all Loans shall not exceed the Aggregate Commitments, and (ii) the aggregate principal amount of the Loans of any Lender shall not exceed such Lender’s Commitment.  If all or a portion of the Outstanding Amount is paid or prepaid, then the amount so paid or prepaid may not be reborrowed.

2.02

Borrowings, Conversions and Continuations of Loans.

(a)

Each Borrowing, each conversion of Loans from one Type to the other, and each continuation of Eurodollar Rate Loans shall be made upon the Borrower’s irrevocable written notice to the Administrative Agent. Each such notice must be received by the Administrative Agent not later than 11:00 a.m. (i) three Business Days prior to the requested date of any Borrowing of, conversion to or continuation of Eurodollar Rate Loans or of any conversion of Eurodollar Rate Loans to Base Rate Loans, and (ii) on the requested date of any Borrowing of Base Rate Loans; provided, however, that if the Borrower wishes to request Eurodollar Rate Loans having an Interest Period other than one, two, three or six months in duration as provided in the definition of “Interest Period,” the applicable notice must be received by the Administrative Agent not later than 11:00 a.m. fou r Business Days prior to the requested date of such Borrowing, conversion or continuation, whereupon the Administrative Agent shall give prompt notice to the Lenders of such request and determine whether the requested Interest Period is acceptable to all of them. Not later than 11:00 a.m., three Business Days before the requested date of such Borrowing, conversion or continuation, the Administrative Agent shall notify the Borrower (which notice may be by telephone) whether or not the requested Interest Period has been consented to by all of the Lenders. Each Borrowing of, conversion to or continuation of Eurodollar Rate Loans shall be in a principal amount of $5,000,000 or a whole multiple of $1,000,000 in excess thereof.  Each Borrowing of or conversion to Base Rate Loans shall be in a principal amount of $500,000 or a whole multiple of $100,000 in excess thereof. Each Loan Notice (whether telephonic or written) shall specify (i) whether the Borrower is requesting a Borrowing, a conversion of Loans fro m one Type to the other, or a continuation of Eurodollar Rate Loans, (ii) the requested date of the Borrowing, conversion or continuation, as the case may be (which shall be a Business Day), (iii) the principal amount of Loans to be borrowed, converted or continued, (iv) the Type of Loans to be borrowed or to which existing Loans are to be converted, and (v) if applicable, the duration of the Interest Period with respect thereto. If the Borrower fails to specify a Type of Loan in a Loan Notice or if the Borrower fails to give a timely notice requesting a conversion or continuation, then the applicable Loans shall be made as, or converted to, Base Rate Loans. Any such automatic conversion to Base Rate Loans shall be effective as of the last day of the Interest Period then in effect with respect to the applicable Eurodollar Rate Loans. If the Borrower requests a Borrowing of, conversion to, or continuation of Eurodollar Rate Loans in any such Loan Notice, but fails to specify an Interest Period, it will be dee med to have specified an Interest Period of one month.

(b)

Following receipt of a Loan Notice, the Administrative Agent shall promptly notify each Lender of the amount of its Pro Rata Share of the applicable Loans, and if no timely notice of a conversion or continuation is provided by the Borrower, the Administrative Agent shall notify each Lender of the details of any automatic conversion to Base Rate Loans described in the preceding subsection. In the case of a Borrowing, each Lender shall make the amount of its Loan available to the Administrative Agent in immediately available funds at the Administrative Agent’s Office not later than 1:00 p.m. on the Business Day specified in the applicable Loan Notice. Upon satisfaction of the applicable conditions set forth in Article IV, the Administrative Agent shall make all funds so received available to the Borrower in like funds as received by the Administrative Agent either by (i) credi ting the account of the Borrower on the books of Bank of America with the amount of such funds or (ii) wire transfer of such funds, in each case in accordance with instructions provided to (and reasonably acceptable to) the Administrative Agent by the Borrower.



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(c)

Except as otherwise provided herein, a Eurodollar Rate Loan may be continued or converted only on the last day of an Interest Period for such Eurodollar Rate Loan. During the existence of a Default, no Loans may be requested as, converted to or continued as Eurodollar Rate Loans without the consent of the Required Lenders.

(d)

The Administrative Agent shall promptly notify the Borrower and the Lenders of the interest rate applicable to any Interest Period for Eurodollar Rate Loans upon determination of such interest rate. The determination of the Eurodollar Rate by the Administrative Agent shall be conclusive in the absence of manifest error. At any time that Base Rate Loans are outstanding, the Administrative Agent shall notify the Borrower and the Lenders of any change in Bank of America’s prime rate used in determining the Base Rate promptly following the public announcement of such change.

(e)

After giving effect to all Borrowings, all conversions of Loans from one Type to the other, and all continuations of Loans as the same Type, there shall not be more than ten Interest Periods in effect with respect to Loans.

2.03

Reserved.

2.04

Prepayments.

(a)

Optional Prepayments.  The Borrower may, upon notice to the Administrative Agent, at any time or from time to time voluntarily prepay Loans in whole or in part without premium or penalty; provided that (i) such notice must be received by the Administrative Agent not later than 11:00 a.m. (A) three Business Days prior to any date of prepayment of Eurodollar Rate Loans and (B) on the date of prepayment of Base Rate Loans; (ii) any prepayment of Eurodollar Rate Loans shall be in a principal amount of $5,000,000 or a whole multiple of $1,000,000 in excess thereof; and (iii) any prepayment of Base Rate Loans shall be in a principal amount of $500,000 or a whole multiple of $100,000 in excess thereof or, in each case, if less, the entire principal amount thereof then outstanding. Each such notice shall specify the date and amount of such prepayment and the Type(s) of Loans to be prepaid. The Administrative Agent will promptly notify each Lender of its receipt of each such notice, and of the amount of such Lender’s Pro Rata Share of such prepayment. If such notice is given by the Borrower, the Borrower shall make such prepayment and the payment amount specified in such notice shall be due and payable on the date specified therein.

(b)

Mandatory Prepayments from Net Cash Proceeds.  Until such time as the Outstanding Amount has been repaid in full, the Outstanding Amount shall be prepaid to the extent provided below:

(i)

Issuance of Indebtedness.  

(A)

Upon the incurrence, issuance or assumption by the Borrower or any of the Borrower’s Subsidiaries of any Indebtedness, the Borrower shall prepay an aggregate principal amount of Loans equal to 100% of all Net Cash Proceeds received therefrom immediately upon receipt thereof by such Person.  In the event that such Net Cash Proceeds exceed the principal amount of Loans then Outstanding, the Commitments shall be reduced (ratably among the Lenders in accordance with their Pro Rata Shares) in the amount of such excess. Notwithstanding the foregoing, for purposes of this Section 2.04(b)(i)(A), the term “Indebtedness” shall not include (x) borrowings by the Borrower under the revolving credit facility established under the Existing Credit Agreement or under any Replacement Revolving Credit Facility; or (y) cash management advances made by Questar C orporation to the Borrower in the ordinary course of business.



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(B)

Concurrently with the effective date of any Replacement Revolving Credit Facility, the Borrower shall prepay Loans made by Bank of America in an amount equal to $200,000,000.  In the event that the Outstanding Amount of Loans made by Bank of America as of such date is less than $200,000,000, then the Commitment of Bank of America shall be reduced by an amount equal to the difference between $200,000,000 and such Outstanding Amount. The prepayment made pursuant to this subsection (B) is herein referred to as the “Revolving Closing Date Prepayment.”

(ii)

Issuance of Equity.  Upon the sale or issuance by the Borrower (or by Subsidiary of the Borrower that is wholly owned) of any Equity Interests, the Borrower shall prepay an aggregate principal amount of Loans equal to 100% of all Net Cash Proceeds received therefrom immediately upon receipt thereof. In the event that such Net Cash Proceeds exceed the principal amount of Loans then Outstanding, the Commitments shall be reduced (ratably among the Lenders in accordance with their Pro Rata Shares) in the amount of such excess.

(iii)

Dispositions.  If the Borrower or any of its Subsidiaries Disposes of any property (in one or more transactions) which results in the receipt by such Persons of Net Cash Proceeds in an aggregate amount after the Closing Date in excess of the Asset Sale Threshold, then the Borrower shall prepay an aggregate principal amount of Loans equal to 100% of Net Cash Proceeds in excess of the Asset Sale Threshold immediately upon receipt thereof by such Person.  In the event that such Net Cash Proceeds exceed the principal amount of Loans then Outstanding, the Commitments shall be reduced (ratably among the Lenders in accordance with their Pro Rata Shares) in the amount of such excess.

(c)

Other Mandatory Prepayments.  If for any reason the Outstanding Amount at any time exceeds the Aggregate Commitments then in effect, the Borrower shall immediately prepay Loans in an aggregate amount equal to such excess.

(d)

General.  Any prepayment of a Eurodollar Rate Loan shall be accompanied by all accrued interest thereon, together with any additional amounts required pursuant to Section 3.05.  Except as otherwise provided in Section  2.04(b)(i)(B) with respect to the Revolving Closing Date Prepayment, each prepayment shall be applied to the Loans of the Lenders in accordance with their respective Pro Rata Shares.

2.05

Termination or Reduction of Commitments

.

(a)

Optional.  The Borrower may, upon notice to the Administrative Agent, terminate the Aggregate Commitments, or from time to time permanently reduce the Aggregate Commitments; provided that (i) any such notice shall be received by the Administrative Agent not later than 11:00 a.m. five Business Days prior to the date of termination or reduction, (ii) any such partial reduction shall be in an aggregate amount of $10,000,000 or any whole multiple of $1,000,000 in excess thereof, and (iii) the Borrower shall not terminate or reduce the Aggregate Commitments if, after giving effect thereto and to any concurrent prepayments hereunder, the Outstanding Amount would exceed the Aggregate Commitments.  In addition, the Borrower may, upon notice to the Administrative Agent as set forth above, from time to time during the Availability Period terminate (in whole or in part) the unused portion of the Aggregate Commitments.

(b)

Mandatory.  



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(i)

The Aggregate Commitments shall be automatically and permanently reduced to zero on the last day of the Availability Period.

(ii)

If Net Cash Proceeds received by the Borrower or its Subsidiaries from the incurrence, issuance or assumption of Indebtedness, the issuance or sale of Equity Interests or Dispositions exceeds the then-outstanding principal amount of Loans, then the Commitments of the Lenders shall be permanently reduced in the manner and in the amounts specified in Section 2.04(b).

(iii)

To the extent the amount of the Bank of America Prepayment does not equal or exceed $200,000,000 (the “Mandatory Prepayment Amount”) because, at the time such prepayment is required, the aggregate amount of all Loans made by Bank of America does not equal or exceed such amount, then the Commitment of Bank of America shall be automatically and permanently reduced in an amount equal to the difference between the Mandatory Prepayment Amount and the aggregate amount of all Loans made by Bank of America at such time (prior to giving effect to any prepayment required under Section 2.04(b)(i)(B) thereof).

(c)

Payment of Fees.  All fees accrued to the effective date of any termination of the Aggregate Commitments shall be paid on the effective date of such termination.

2.06

Repayment of Loans

.  The Borrower shall repay to the Lenders on the Maturity Date the aggregate principal amount of Loans outstanding on such date.

2.07

Interest.

(a)

Subject to the provisions of subsection (b) below, (i) each Eurodollar Rate Loan shall bear interest on the outstanding principal amount thereof for each Interest Period at a rate per annum equal to the Eurodollar Rate for such Interest Period plus the Applicable Rate; and (ii) each Base Rate Loan shall bear interest on the outstanding principal amount thereof from the applicable borrowing date at a rate per annum equal to the Base Rate.

(b)

5)

If any amount of principal of any Loan is not paid when due (without regard to any applicable grace periods), whether at stated maturity, by acceleration or otherwise, such amount shall thereafter bear interest at a fluctuating interest rate per annum at all times equal to the Default Rate to the fullest extent permitted by applicable Laws.

6)

If any amount (other than principal of any Loan) payable by the Borrower under any Loan Document is not paid when due (without regard to any applicable grace periods), whether at stated maturity, by acceleration or otherwise, then upon the request of the Required Lenders, such amount shall thereafter bear interest at a fluctuating interest rate per annum at all times equal to the Default Rate to the fullest extent permitted by applicable Laws.

7)

Upon the request of the Required Lenders, while any Event of Default exists, the Borrower shall pay interest on the principal amount of all outstanding Obligations hereunder at a fluctuating interest rate per annum at all times equal to the Default Rate to the fullest extent permitted by applicable Laws.

8)

Accrued and unpaid interest on past due amounts (including interest on past due interest) shall be due and payable upon demand.



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(c)

Interest on each Loan shall be due and payable in arrears on each Interest Payment Date applicable thereto and at such other times as may be specified herein. Interest hereunder shall be due and payable in accordance with the terms hereof before and after judgment, and before and after the commencement of any proceeding under any Debtor Relief Law.

2.08

Fees

.  

(a)

Commitment Fee.  The Borrower shall pay to the Administrative Agent for the account of each Lender in accordance with its Pro Rata Share, a commitment fee equal to the Applicable Rate times the actual daily amount by which the Aggregate Commitments exceed the sum of the Outstanding Amount of Loans. The commitment fee shall accrue at all times during the Availability Period, including at any time during which one or more of the conditions in Article IV is not met, and shall be due and payable quarterly in arrears (i) promptly after Borrower receives notice of the amount of such commitment fee for such quarter, but not earlier than the last Business Day of each March, June, and September, commencing with the first such date to occur after the Closing Date, and (ii) on the Maturity Date.  The commitment fee shall be calculated quarterly in arrears, and if there is a ny change in the Applicable Rate during any quarter, the actual daily amount shall be computed and multiplied by the Applicable Rate separately for each period during such quarter that such Applicable Rate was in effect.

(b)

Other Fees.

(i)

The Borrower shall pay to the Arranger and the Administrative Agent for their own respective accounts fees in the amounts and at the times specified in the Fee Letter. Such fees shall be fully earned when paid and shall not be refundable for any reason whatsoever.

(ii)

The Borrower shall pay to the Lenders such fees as shall have been separately agreed upon in writing in the amounts and at the times so specified. Such fees shall be fully earned when paid and shall not be refundable for any reason whatsoever.

2.09

Computation of Interest and Fees

.  

All computations of interest for Base Rate Loans when the Base Rate is determined by Bank of America’s “prime rate” shall be made on the basis of a year of 365 or 366 days, as the case may be, and actual days elapsed. All other computations of fees and interest shall be made on the basis of a 360-day year and actual days elapsed (which results in more fees or interest, as applicable, being paid than if computed on the basis of a 365-day year). Interest shall accrue on each Loan for the day on which the Loan is made, and shall not accrue on a Loan, or any portion thereof, for the day on which the Loan or such portion is paid, provided that any Loan that is repaid on the same day on which it is made shall, subject to Section 2.11(a), bear interest for one day.

2.10

Evidence of Debt.

  The Loans made by each Lender shall be evidenced by one or more accounts or records maintained by such Lender and by the Administrative Agent in the ordinary course of business. The accounts or records maintained by the Administrative Agent and each Lender shall be conclusive absent manifest error of the amount of the Loans made by the Lenders to the Borrower and the interest and payments thereon. Any failure to so record or any error in doing so shall not, however, limit or otherwise



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affect the obligation of the Borrower hereunder to pay any amount owing with respect to the Obligations. In the event of any conflict between the accounts and records maintained by any Lender and the accounts and records of the Administrative Agent in respect of such matters, the accounts and records of the Administrative Agent shall control in the absence of manifest error. Upon the request of any Lender made through the Administrative Agent, the Borrower shall execute and deliver to such Lender (through the Administrative Agent) a Note, which shall evidence such Lender’s Loans in addition to such accounts or records. Each Lender may attach schedules to its Note and endorse thereon the date, Type (if applicable), amount and maturity of its Loans and payments with respect thereto.

2.11

Payments Generally.

(a)

All payments to be made by the Borrower shall be made without condition or deduction for any counterclaim, defense, recoupment or setoff. Except as otherwise expressly provided herein, all payments by the Borrower hereunder shall be made to the Administrative Agent, for the account of the respective Lenders to which such payment is owed, at the Administrative Agent’s Office in Dollars and in immediately available funds not later than 2:00 p.m. on the date specified herein. The Administrative Agent will promptly distribute to each Lender its Pro Rata Share (or other applicable share as provided herein) of such payment in like funds as received by wire transfer to such Lender’s Lending Office. All payments received by the Administrative Agent after 2:00 p.m. shall be deemed received on the next succeeding Business Day and any applicable interest or fee shall continue to accrue.< /P>

(b)

If any payment to be made by the Borrower shall come due on a day other than a Business Day, payment shall be made on the next following Business Day, and such extension of time shall be reflected in computing interest or fees, as the case may be.

(c)

(i)

Unless the Administrative Agent shall have received notice from a Lender prior to the proposed date of any Borrowing of Eurodollar Rate Loans (or, in the case of any Borrowing of Base Rate Loans, prior to 12:00 noon on the date of such Borrowing) that such Lender will not make available to the Administrative Agent such Lender’s share of such Borrowing, the Administrative Agent may assume that such Lender has made such share available on such date in accordance with Section 2.02 (or, in the case of a Borrowing of Base Rate Loans, that such Lender has made such share available in accordance with and at the time required by Section 2.02) and may, in reliance upon such assumption, make available to the Borrower a corresponding amount.  In such event, if a Lender has not in fact made its share of the applicable Borrowing available to the Administrative Agent, then th e applicable Lender and the Borrower severally agree to pay to the Administrative Agent forthwith on demand such corresponding amount in immediately available funds with interest thereon, for each day from and including the date such amount is made available to the Borrower to but excluding the date of payment to the Administrative Agent, at (A) in the case of a payment to be made by such Lender, the Federal Funds Rate plus any administrative, processing or similar fees customarily charged by the Administrative Agent in connection with the foregoing, and (B) in the case of a payment to be made by the Borrower, the interest rate applicable to Base Rate Loans.  If the Borrower and such Lender shall pay such interest to the Administrative Agent for the same or an overlapping period, the Administrative Agent shall promptly remit to the Borrower the amount of such interest paid by the Borrower for such period.  If such Lender pays its share of the applicable Borrowing to the Administrative Agent, then t he amount so paid shall constitute such Lender’s Loan included in such Borrowing.  Any payment by the Borrower shall be without prejudice to any claim the Borrower may have against a Lender that shall have failed to make such payment to the Administrative Agent.

(ii)

Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Administrative Agent for the account of the Lenders hereunder that the Borrower will not make such payment, the Administrative Agent may assume that the



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Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute to the Lenders the amount due.  In such event, if the Borrower has not in fact made such payment, then each of the Lenders severally agrees to repay to the Administrative Agent forthwith on demand the amount so distributed to such Lender, in immediately available funds with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to the Administrative Agent, at the Federal Funds Rate.

A notice of the Administrative Agent to any Lender or the Borrower with respect to any amount owing under this subsection (c) shall be conclusive, absent manifest error.

(d)

If any Lender makes available to the Administrative Agent funds for any Loan to be made by such Lender as provided in the foregoing provisions of this Article II, and such funds are not made available to the Borrower by the Administrative Agent because the conditions to the applicable Loans set forth in Article IV are not satisfied or waived in accordance with the terms hereof, the Administrative Agent shall return such funds (in like funds as received from such Lender) to such Lender, without interest.

(e)

The obligations of the Lenders hereunder to make Loans and to make payments pursuant to Section 10.04(c) are several and not joint.  The failure of any Lender to make any Loan or to make any payment under Section 10.04(c) on any date required hereunder shall not relieve any other Lender of its corresponding obligation to do so on such date, and no Lender shall be responsible for the failure of any other Lender to so make its Loan or to make its payment under Section 10.04(c).

(f)

Nothing herein shall be deemed to obligate any Lender to obtain the funds for any Loan in any particular place or manner or to constitute a representation by any Lender that it has obtained or it will obtain the funds for any Loan in any particular place or manner.

2.12

Sharing of Payments

.  If any Lender shall, by exercising any right of setoff or counterclaim or otherwise, obtain payment in respect of any principal of or interest on any of the Loans made by it, resulting in such Lender’s receiving payment of a proportion of the aggregate amount of such Loans or participations and accrued interest thereon greater than its pro rata share thereof as provided herein, then the Lender receiving such greater proportion shall (a) notify the Administrative Agent of such fact, and (b) purchase (for cash at face value) participations in the Loans of the other Lenders, or make such other adjustments as shall be equitable, so that the benefit of all such payments shall be shared by the Lenders ratably in accordance with the aggregate amount of principal of and accrued interest on their respective Loans and other amounts owing them, provided that:

(i)

if any such participations or subparticipations are purchased and all or any portion of the payment giving rise thereto is recovered, such participations or subparticipations shall be rescinded and the purchase price restored to the extent of such recovery, without interest; and

(ii)

the provisions of this Section shall not be construed to apply to (x) any payment made by the Borrower pursuant to and in accordance with the express terms of this Agreement or (y) any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans to any assignee or participant, other than to the Borrower or any Subsidiary thereof (as to which the provisions of this Section shall apply).



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ARTICLE III.
TAXES, YIELD PROTECTION AND ILLEGALITY

3.01

Taxes.

(a)

Payments Free of Taxes; Obligation to Withhold; Payments on Account of Taxes.

(i)

Any and all payments by or on account of any obligation of the Borrower hereunder or under any other Loan Document shall to the extent permitted by applicable Laws be made free and clear of and without reduction or withholding for any Taxes.  If, however, applicable Laws require the Borrower or the Administrative Agent to withhold or deduct any Tax, such Tax shall be withheld or deducted in accordance with such Laws as determined by the Borrower or the Administrative Agent, as the case may be, upon the basis of the information and documentation to be delivered pursuant to subsection (e) below.

(ii)

If the Borrower or the Administrative Agent shall be required by the Code to withhold or deduct any Taxes, including both United States Federal backup withholding and withholding taxes, from any payment, then (A) the Administrative Agent shall withhold or make such deductions as are determined by the Administrative Agent to be required based upon the information and documentation it has received pursuant to subsection (e) below, (B) the Administrative Agent shall timely pay the full amount withheld or deducted to the relevant Governmental Authority in accordance with the Code, and (C) to the extent that the withholding or deduction is made on account of Indemnified Taxes or Other Taxes, the sum payable by the Borrower shall be increased as necessary so that after any required withholding or the making of all required deductions (including deductions applicable to additional sums payable under this Section) the Administrative Agent or Lender, as the case may be, receives an amount equal to the sum it would have received had no such withholding or deduction been made.

(b)

Payment of Other Taxes by the Borrower.  Without limiting the provisions of subsection (a) above, the Borrower shall timely pay any Other Taxes to the relevant Governmental Authority in accordance with applicable Laws.

(c)

Tax Indemnifications.

(i)

Without limiting the provisions of subsection (a) or (b) above, the Borrower shall, and does hereby, indemnify the Administrative Agent and each Lender, and shall make payment in respect thereof within 10 days after demand therefor, for the full amount of any Indemnified Taxes or Other Taxes (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section) withheld or deducted by the Borrower or the Administrative Agent or paid by the Administrative Agent or such Lender, as the case may be, and any penalties, interest and reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority.  The Borrower shall also, and does hereby, indemnify the Administrative Agent, and shall make payment in respect thereof within 10 days after demand therefor, for any amount which a Lender for any reason fails to pay indefeasibly to the Administrative Agent as required by clause (ii) of this subsection.  A certificate as to the amount of any such payment or liability delivered to the Borrower by a Lender (with a copy to the Administrative Agent), or by the Administrative Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.



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(ii)

Without limiting the provisions of subsection (a) or (b) above, each Lender shall, and does hereby, indemnify the Borrower and the Administrative Agent, and shall make payment in respect thereof within 10 days after demand therefor, against any and all Taxes and any and all related losses, claims, liabilities, penalties, interest and expenses (including the fees, charges and disbursements of any counsel for the Borrower or the Administrative Agent) incurred by or asserted against the Borrower or the Administrative Agent by any Governmental Authority as a result of the failure by such Lender to deliver, or as a result of the inaccuracy, inadequacy or deficiency of, any documentation required to be delivered by such Lender to the Borrower or the Administrative Agent pursuant to subsection (e).  Each Lender hereby authorizes the Administrative Agent to set of f and apply any and all amounts at any time owing to such Lender under this Agreement or any other Loan Document against any amount due to the Administrative Agent under this clause (ii).  The agreements in this clause (ii) shall survive the resignation and/or replacement of the Administrative Agent, any assignment of rights by, or the replacement of, a Lender, the termination of the Aggregate Commitments and the repayment, satisfaction or discharge of all other Obligations.

(d)

Evidence of Payments.  Upon request by the Borrower or the Administrative Agent, as the case may be, after any payment of Taxes by the Borrower or by the Administrative Agent to a Governmental Authority as provided in this Section 3.01, the Borrower shall deliver to the Administrative Agent or the Administrative Agent shall deliver to the Borrower, as the case may be, the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of any return required by Laws to report such payment or other evidence of such payment reasonably satisfactory to the Borrower or the Administrative Agent, as the case may be.

(e)

Status of Lenders; Tax Documentation.

(i)

Each Lender shall deliver to the Borrower and to the Administrative Agent, at the time or times prescribed by applicable Laws or when reasonably requested by the Borrower or the Administrative Agent, such properly completed and executed documentation prescribed by applicable Laws or by the taxing authorities of any jurisdiction and such other reasonably requested information as will permit the Borrower or the Administrative Agent, as the case may be, to determine (A) whether or not payments made hereunder or under any other Loan Document are subject to Taxes, (B) if applicable, the required rate of withholding or deduction, and (C) such Lender’s entitlement to any available exemption from, or reduction of, applicable Taxes in respect of all payments to be made to such Lender by the Borrower pursuant to this Agreement or otherwise to establish such Lender’s s tatus for withholding tax purposes in the applicable jurisdiction.

(ii)

Without limiting the generality of the foregoing, if the Borrower is resident for tax purposes in the United States,

(A)

any Lender that is a “United States person” within the meaning of Section 7701(a)(30) of the Code shall deliver to the Borrower and the Administrative Agent executed originals of Internal Revenue Service Form W-9 or such other documentation or information prescribed by applicable Laws or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent, as the case may be, to determine whether or not such Lender is subject to backup withholding or information reporting requirements; and

(B)

each Foreign Lender that is entitled under the Code or any applicable treaty to an exemption from or reduction of withholding tax with respect to payments



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hereunder or under any other Loan Document shall deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the request of the Borrower or the Administrative Agent, but only if such Foreign Lender is legally entitled to do so), whichever of the following is applicable:

(I)

executed originals of Internal Revenue Service Form W-8BEN claiming eligibility for benefits of an income tax treaty to which the United States is a party,

(II)

executed originals of Internal Revenue Service Form W-8ECI,

(III)

executed originals of Internal Revenue Service Form W-8IMY and all required supporting documentation,

(IV)

in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under section 881(c) of the Code, (x) a certificate to the effect that such Foreign Lender is not (A) a “bank” within the meaning of section 881(c)(3)(A) of the Code, (B) a “10 percent shareholder” of the Borrower within the meaning of section 881(c)(3)(B) of the Code, or (C) a “controlled foreign corporation” described in section 881(c)(3)(C) of the Code and (y) executed originals of  Internal Revenue Service Form W-8BEN, or

(V)

executed originals of any other form prescribed by applicable Laws as a basis for claiming exemption from or a reduction in United States Federal withholding tax together with such supplementary documentation as may be prescribed by applicable Laws to permit the Borrower or the Administrative Agent to determine the withholding or deduction required to be made.

(iii)

Each Lender shall promptly (A) notify the Borrower and the Administrative Agent of any change in circumstances which would modify or render invalid any claimed exemption or reduction, and (B) take such steps as shall not be materially disadvantageous to it, in the reasonable judgment of such Lender, and as may be reasonably necessary (including the re-designation of its Lending Office) to avoid any requirement of applicable Laws of any jurisdiction that the Borrower or the Administrative Agent make any withholding or deduction for taxes from amounts payable to such Lender.

(f)

Treatment of Certain Refunds.  Unless required by applicable Laws, at no time shall the Administrative Agent have any obligation to file for or otherwise pursue on behalf of a Lender, or have any obligation to pay to any Lender, any refund of Taxes withheld or deducted from funds paid for the account of such Lender.  If the Administrative Agent or any Lender determines, in its sole discretion, that it has received a refund of any Taxes or Other Taxes as to which it has been indemnified by the Borrower or with respect to which the Borrower has paid additional amounts pursuant to this Section, it shall pay to the Borrower an amount equal to such refund (but only to the extent of indemnity payments made, or additional amounts paid, by the Borrower under this Section with respect to the Taxes or Other Taxes giving rise to such refund), net of all out-of-pocket expenses incu rred by the Administrative Agent or such Lender, as the case may be, and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund), provided that the Borrower, upon the request of the Administrative Agent or such Lender, agrees to repay the amount paid over to the Borrower (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the



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Administrative Agent or such Lender in the event the Administrative Agent or such Lender is required to repay such refund to such Governmental Authority.  This subsection shall not be construed to require the Administrative Agent or any Lender to make available its tax returns (or any other information relating to its taxes that it deems confidential) to the Borrower or any other Person.

3.02

Illegality

.  If any Lender determines that any Law has made it unlawful, or that any Governmental Authority has asserted that it is unlawful, for any Lender or its applicable Lending Office to make, maintain or fund Eurodollar Rate Loans, or to determine or charge interest rates based upon the Eurodollar Rate, then, on notice thereof by such Lender to the Borrower through the Administrative Agent, any obligation of such Lender to make or continue Eurodollar Rate Loans or to convert Base Rate Loans to Eurodollar Rate Loans shall be suspended until such Lender notifies the Administrative Agent and the Borrower that the circumstances giving rise to such determination no longer exist. Upon receipt of such notice, the Borrower shall, upon demand from such Lender (with a copy to the Administrative Agent), prepay or, if applicable, convert all Eurodollar Rate Loans of such Lender to Base Rate Loans , either on the last day of the Interest Period therefor, if such Lender may lawfully continue to maintain such Eurodollar Rate Loans to such day, or immediately, if such Lender may not lawfully continue to maintain such Eurodollar Rate Loans. Upon any such prepayment or conversion, the Borrower shall also pay accrued interest on the amount so prepaid or converted. Each Lender agrees to designate a different Lending Office if such designation will avoid the need for such notice and will not, in the good faith judgment of such Lender, otherwise be materially disadvantageous to such Lender.

3.03

Inability to Determine Rates

.  If the Required Lenders determine that for any reason adequate and reasonable means do not exist for determining the Eurodollar Rate for any requested Interest Period with respect to a proposed Eurodollar Rate Loan, or that the Eurodollar Rate for any requested Interest Period with respect to a proposed Eurodollar Rate Loan does not adequately and fairly reflect the cost to such Lenders of funding such Loan, the Administrative Agent will promptly so notify the Borrower and each Lender. Thereafter, the obligation of the Lenders to make or maintain Eurodollar Rate Loans shall be suspended until the Administrative Agent (upon the instruction of the Required Lenders) revokes such notice. Upon receipt of such notice, the Borrower may revoke any pending request for a Borrowing of, conversion to or continuation of Eurodollar Rate Loans or, failing that, will be deemed to have converted such request into a request for a Borrowing of Base Rate Loans in the amount specified therein.

3.04

Increased Cost and Reduced Return; Capital Adequacy; Reserves on Eurodollar Rate Loans.

(a)

If any Lender determines that as a result of the introduction of or any change in or in the interpretation of any Law, or such Lender’s compliance therewith, there shall be any increase in the cost to such Lender of agreeing to make or making, funding or maintaining Eurodollar Rate Loans, or a reduction in the amount received or receivable by such Lender in connection with any of the foregoing (excluding for purposes of this subsection (a) any such increased costs or reduction in amount resulting from (i) Taxes or Other Taxes (as to which Section 3.01 shall govern), (ii) changes in the basis of taxation of overall net income or overall gross income by the United States or any foreign jurisdiction or any political subdivision of either thereof under the Laws of which such Lender is organized or has its Lending Office, and (iii) reserve requirements contemplated by S ection 3.04(c)), then from time to time upon demand of such Lender (with a copy of such demand to the Administrative Agent), the Borrower shall pay to such Lender such additional amounts as will compensate such Lender for such increased cost or reduction.



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(b)

If any Lender determines that the introduction of any Law regarding capital adequacy or any change therein or in the interpretation thereof, or compliance by such Lender (or its Lending Office) therewith, has the effect of reducing the rate of return on the capital of such Lender or any corporation controlling such Lender as a consequence of such Lender’s obligations hereunder (taking into consideration its policies with respect to capital adequacy and such Lender’s desired return on capital), then from time to time upon demand of such Lender (with a copy of such demand to the Administrative Agent), the Borrower shall pay to such Lender such additional amounts as will compensate such Lender for such reduction.

(c)

The Borrower shall pay to each Lender, as long as such Lender shall be required to maintain reserves with respect to liabilities or assets consisting of or including Eurocurrency funds or deposits (currently known as “Eurocurrency liabilities”), additional interest on the unpaid principal amount of each Eurodollar Rate Loan equal to the actual costs of such reserves allocated to such Loan by such Lender (as determined by such Lender in good faith, which determination shall be conclusive), which shall be due and payable on each date on which interest is payable on such Loan, provided the Borrower shall have received at least 15 days’ prior notice (with a copy to the Administrative Agent) of such additional interest from such Lender. If a Lender fails to give notice 15 days prior to the relevant Interest Payment Date, such additional interest shall be due and payable 15 days from receipt of such notice.

3.05

 Compensation for Losses

.  Upon demand of any Lender (with a copy to the Administrative Agent) from time to time, the Borrower shall promptly compensate such Lender for and hold such Lender harmless from any loss, cost or expense incurred by it as a result of:

(a)

any continuation, conversion, payment or prepayment of any Loan other than a Base Rate Loan on a day other than the last day of the Interest Period for such Loan (whether voluntary, mandatory, automatic, by reason of acceleration, or otherwise); or

(b)

any failure by the Borrower (for a reason other than the failure of such Lender to make a Loan) to prepay, borrow, continue or convert any Loan other than a Base Rate Loan on the date or in the amount notified by the Borrower; or

(c)

any assignment of a Eurodollar Rate Loan on a day other than the last day of the Interest Period therefor as a result of a request by the Borrower pursuant to Section 10.15;

including any loss of anticipated profits and any loss or expense arising from the liquidation or reemployment of funds obtained by it to maintain such Loan or from fees payable to terminate the deposits from which such funds were obtained. The Borrower shall also pay any customary administrative fees charged by such Lender in connection with the foregoing.

For purposes of calculating amounts payable by the Borrower to the Lenders under this Section 3.05, each Lender shall be deemed to have funded each Eurodollar Rate Loan made by it at the Eurodollar Rate for such Loan by a matching deposit or other borrowing in the London interbank eurodollar market for a comparable amount and for a comparable period, whether or not such Eurodollar Rate Loan was in fact so funded.

3.06

Matters Applicable to all Requests for Compensation.



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(a)

A certificate of the Administrative Agent or any Lender claiming compensation under this Article III and setting forth the additional amount or amounts to be paid to it hereunder shall be conclusive in the absence of manifest error. In determining such amount, the Administrative Agent or such Lender may use any reasonable averaging and attribution methods.

(b)

Upon any Lender’s making a claim for compensation under Section 3.01 or 3.04, or if the Borrower is required to pay any amount to any Governmental Authority for the account of any Lender pursuant to Section 3.01, the Borrower may replace such Lender in accordance with Section 10.15.

3.07

Survival

.  All of the Borrower’s obligations under this Article III shall survive termination of the Aggregate Commitments and repayment of all other Obligations hereunder.

ARTICLE IV.
CONDITIONS PRECEDENT TO EFFECTIVENESS AND BORROWINGS

4.01

Conditions to Effectiveness of this Agreement

.  The effectiveness of this Agreement and the obligation of each Lender to make Loans hereunder are subject to satisfaction of the following conditions precedent:  

(a)

The Administrative Agent’s receipt of the following, each of which shall be originals or facsimiles (followed promptly by originals) unless otherwise specified, each properly executed by a Responsible Officer of the signing Loan Party, each dated the Closing Date (or, in the case of certificates of governmental officials, a recent date before the Closing Date) and each in form and substance satisfactory to the Administrative Agent and each of the Lenders:

(i)

executed counterparts of this Agreement, sufficient in number for distribution to the Administrative Agent, each Lender and the Borrower;

(ii)

a Note executed by the Borrower in favor of each Lender requesting a Note;

(iii)

such certificates of resolutions or other action, incumbency certificates and/or other certificates of Responsible Officers of each Loan Party as the Administrative Agent may require evidencing the identity, authority and capacity of each Responsible Officer thereof authorized to act as a Responsible Officer in connection with this Agreement and the other Loan Documents to which such Loan Party is a party;

(iv)

such documents and certifications as the Administrative Agent may reasonably require to evidence that each Loan Party is duly organized or formed, and that the Borrower is validly existing, in good standing and qualified to engage in business in each jurisdiction within the United States wherein the character of the properties owned or held by it or the nature of the business transacted by it makes such qualification necessary;

(v)

a favorable opinion of  Thomas Jepperson, General Counsel for the Loan Parties, addressed to the Administrative Agent and each Lender, and a favorable opinion of  Terrie McIntosh, Senior Corporate Counsel for the Loan Parties, addressed to the Administrative Agent and each Lender, as to the matters set forth in Exhibit E and such other matters concerning the Loan Parties and the Loan Documents as the Required Lenders may reasonably request; and



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(vi)

a certificate of a Responsible Officer of each Loan Party either (A) attaching copies of all consents, licenses and approvals required in connection with the execution, delivery and performance by such Loan Party and the validity against such Loan Party of the Loan Documents to which it is a party, and such consents, licenses and approvals shall be in full force and effect, or (B) stating that no such consents, licenses or approvals are so required;

(b)

a certificate signed by a Responsible Officer of the Borrower certifying the current Debt Ratings, which shall be not lower than BBB- from S&P and Baa3 from Moody’s.

(c)

The Administrative Agent shall have received all fees and other amounts due and payable on or prior to the Closing Date, including, to the extent invoiced, reimbursement or payment of all expenses (including, without limitation, Attorney Costs) required to be reimbursed or paid by the Borrower hereunder.

Without limiting the generality of the provisions of the last paragraph of Section 9.03, for purposes of determining compliance with the conditions specified in this Section 4.01, each Lender that has signed this Agreement shall be deemed to have consented to, approved or accepted or to be satisfied with, each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to a Lender unless the Administrative Agent shall have received notice from such Lender prior to the proposed Closing Date specifying its objection thereto.

4.02

Conditions to Initial Loans

.  The obligations of each Lender to fund its initial Loan hereunder is subject to satisfaction of the following condition precedent: There shall not have occurred since the date of the Audited Financial Statements any event or condition that has had or could be reasonably expected to have, either individually or in the aggregate, a Material Adverse Effect or a material adverse effect upon the Borrower’s ability to perform its obligations under any Loan Document to which it is a party, and the Administrative Agent shall have received a certificate signed by a Responsible Officer of the Borrower certifying thereto.

4.03

Conditions to Each Loan

.  The obligation of each Lender to make any Loan hereunder  (including its initial Loan) is subject to the satisfaction of the following conditions precedent:

(a)

Both before and after giving effect to the funding of the Loans and the proposed Acquisition the purchase price of which will be funded in whole or in part thereby, (i) the representations and warranties set forth in this Agreement (excluding the representation and warranty set forth in Section 5.06(c) (provided however that this exclusion shall not apply to the initial Borrowing and shall not apply to a Loan to fund in whole or in part the purchase price of the Elm Grove Field Acquisition)) are true and correct (except to the extent that such representations and warranties relate solely to an earlier date, in which case they shall be true and correct as of such earlier date), and (ii) no Default then exists or would result therefrom.  

(b)

The Administrative Agent shall have received a certificate signed by a Responsible Officer of the Borrower certifying as to the accuracy of the matters set forth in clause (a) of this Section 4.03.  

4.04

Additional Condition to Loans for the Elm Grove Field Acquisition



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.  The obligation of each Lender to make Loans hereunder to finance in whole or in part the purchase price for the Elm Grove Field Acquisition is subject to the satisfaction of the following additional conditions precedent:

(a)

There shall not have occurred since the date of the Audited Financial Statements any event or condition that has had or could be reasonably expected to have, either individually or in the aggregate, a Material Adverse Effect or any material adverse effect upon the Borrower’s ability to perform its obligations under any Loan Document to which it is a party, and the Administrative Agent shall have received a certificate signed by a Responsible Officer of the Borrower certifying thereto; and

(b)

The Administrative Agent shall have received copies of such documentation relating to the Elm Grove Field Acquisition as the Administrative Agent may reasonably request, together with a certificate of a Responsible Officer certifying that true and correct copies thereof have been delivered to the Administrative Agent or are attached thereto.

ARTICLE V.
REPRESENTATIONS AND WARRANTIES

To confirm each Lender’s understanding concerning Loan Parties and Loan Parties’ businesses, properties and obligations and to induce each Lender to enter into this Agreement and to extend credit hereunder, the Borrower represents and warrants to each Lender that:

5.01

No Default

.  No event has occurred and is continuing which constitutes a Default.

5.02

Organization and Good Standing

.  Each Loan Party is duly organized, validly existing and in good standing under the Laws of its jurisdiction of organization, having all powers required to carry on its business and enter into and carry out the transactions contemplated hereby. Each Loan Party is duly qualified, in good standing, and authorized to do business in all other jurisdictions within the United States wherein the character of the properties owned or held by it or the nature of the business transacted by it makes such qualification necessary. Each Loan Party has taken all actions and procedures customarily taken in order to enter, for the purpose of conducting business or owning property, each jurisdiction outside the United States wherein the character of the properties owned or held by it or the nature of the business transacted by it makes such actions and procedures desirable.

5.03

Authorization

.  The Borrower has duly taken all action necessary to authorize the execution and delivery by it of the Loan Documents to which it is a party and to authorize the consummation of the transactions contemplated thereby and the performance of its obligations thereunder. The Borrower is duly authorized to borrow funds hereunder.

5.04

No Conflicts or Consents

.  The execution and delivery by the various Loan Parties of the Loan Documents to which each is a party, the performance by each of its obligations under such Loan Documents, and the consummation of the transactions contemplated by the various Loan Documents, do not and will not (a) conflict with any provision of (i) any Law, (ii) the Organization Documents of any Loan Party, or (iii) any agreement,



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judgment, license, order or permit applicable to or binding upon any Loan Party, or (b) result in the acceleration of any Indebtedness owed by any Loan Party, or (c) result in or require the creation of any Lien upon any assets or properties of any Loan Party, except as expressly contemplated or permitted in the Loan Documents. Except as expressly contemplated in the Loan Documents no consent, approval, authorization or order of, and no notice to or filing with, any Governmental Authority or third party is required in connection with the execution, delivery or performance by any Loan Party of any Loan Document or to consummate any transactions contemplated by the Loan Documents.

5.05

Enforceable Obligations

.  This Agreement is, and the other Loan Documents when duly executed and delivered will be, legal, valid and binding obligations of each Loan Party which is a party hereto or thereto, enforceable in accordance with their terms except as such enforcement may be limited by bankruptcy, insolvency or similar Laws of general application relating to the enforcement of creditors’ rights.

5.06

Audited Financial Statements.

(a)

The Borrower has heretofore delivered to each Lender true, correct and complete copies of the Audited Financial Statements. The Audited Financial Statements (i) fairly present the Borrower’s consolidated financial position at the respective dates thereof and the consolidated results of the Borrower’s operations and the Borrower’s consolidated cash flows for the respective periods thereof, and (ii) show all material indebtedness and other liabilities, direct or contingent, of the Borrower and its Subsidiaries as of the date thereof, including liabilities for taxes, material commitments and Indebtedness. All Audited Financial Statements were prepared in accordance with GAAP.

(b)

The unaudited consolidated balance sheet of the Borrower and its Subsidiaries dated September 30, 2007, and the related consolidated statements of income or operations, shareholders’ equity and cash flows for the fiscal quarter ended on that date (i) were prepared in accordance with GAAP consistently applied throughout the period covered thereby, except as otherwise expressly noted therein, and (ii) fairly present the Borrower’s consolidated financial condition as of the date thereof and their results of operations for the period covered thereby, subject, in the case of clauses (i) and (ii), to the absence of footnotes and to normal year-end adjustments.

(c)

Since the date of the annual Audited Financial Statements no event which would cause a Material Adverse Effect has occurred.

5.07

Other Obligations and Restrictions

.  No Loan Party has any outstanding indebtedness, liabilities or obligations of any kind (including contingent obligations, tax assessments, and unusual forward or long-term commitments) which are, in the aggregate, material to the Borrower or material with respect to the Borrower’s consolidated financial condition and not shown in the Audited Financial Statements or disclosed on Schedule 5.07. Except as shown in the Audited Financial Statements or disclosed on Schedule 5.07, no Loan Party is subject to or restricted by any franchise, contract, deed, charter restriction, or other instrument or restriction which could cause a Material Adverse Effect.

5.08

Full Disclosure

.  No certificate, statement or other information delivered herewith or heretofore by any Loan Party to any Lender in connection with the negotiation of this Agreement or in connection with any transaction contemplated hereby contains any untrue statement of a material fact or omits to state any



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material fact known to any Loan Party (other than industry-wide risks normally associated with the types of businesses conducted by Loan Parties) necessary to make the statements contained herein or therein not misleading as of the date made or deemed made. There is no fact known to the Borrower (other than industry-wide risks normally associated with the types of businesses conducted by Loan Parties) that has not been disclosed by the Borrower to each Lender in writing which would reasonably be expected to have a Material Adverse Effect.

5.09

Litigation

.  Except as disclosed in the Annual Report on Form 10-K or the Quarterly Report on Form 10-Q of Borrower filed with the SEC, there are no actions, suits or legal, equitable, arbitrative or administrative proceedings pending, or to the knowledge of any Loan Party threatened, against any Loan Party before any Governmental Authority which would reasonably be expected to have a Material Adverse Effect, and there are no outstanding judgments, injunctions, writs, rulings or orders by any such Governmental Authority against any Loan Party which would reasonably be expected to have a Material Adverse Effect.

5.10

Labor Disputes and Acts of God

.  Except as disclosed on Schedule 5.10, neither the business nor the properties of any Loan Party has been affected by any fire, explosion, accident, strike, lockout or other labor dispute, drought, storm, hail, earthquake, embargo, act of God or of the public enemy or other casualty (whether or not covered by insurance), which would reasonably be expected to have a Material Adverse Effect.

5.11

ERISA Plans and Liabilities

.  All currently existing Pension Plans are listed on Schedule 5.11. Except as disclosed in the Audited Financial Statements or on Schedule 5.11, no ERISA Event has occurred with respect to any Pension Plan and all ERISA Affiliates are in compliance with ERISA in all material respects. No ERISA Affiliate is required to contribute to, or has any other absolute or contingent liability in respect of, any Multiemployer Plan. Except as set forth on Schedule 5.11, no “accumulated funding deficiency” (as defined in Section 412(a) of the Internal Revenue Code) exists with respect to any Pension Plan, whether or not waived by the Secretary of the Treasury or his delegate, and the current value of the accumulated benefit obligation of each Pension Plan does not exceed the current value of the assets of such Pension Plan available for the payment of such benefit s by more than $30,000,000.

5.12

Environmental and Other Laws

.  Except as disclosed in the Annual Report on Form 10-K or the Quarterly Report on Form 10-Q of Borrower filed with the SEC, or on Schedule 5.12: (a) Loan Parties are conducting their businesses in material compliance with all applicable Laws, including Environmental Laws, and have and are in material compliance with all licenses and permits required under any such Laws; (b) none of the operations or properties of any Loan Party is the subject of federal, state or local investigation evaluating whether any material remedial action is needed to respond to a release of any Hazardous Materials into the environment or to the improper storage or disposal (including storage or disposal at offsite locations) of any Hazardous Materials; (c) no Loan Party (and to the best knowledge of the Borrower, no other Person) has filed any notice under any Law indicating that any Loan Party is responsible for the improper release into the environment, or the improper storage or disposal, of any material amount of any Hazardous Materials or that any Hazardous Materials have been improperly released, or are improperly stored or disposed of, upon any property of any Loan Party; (d) no Loan Party has transported or arranged for the transportation of any Hazardous Material to any location which is (i) listed on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act of



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1980, as amended, listed for possible inclusion on such National Priorities List by the Environmental Protection Agency in its Comprehensive Environmental Response, Compensation and Liability Information System List, or listed on any similar state list or (ii) the subject of federal, state or local enforcement actions or other investigations which may lead to claims against any Loan Party for clean-up costs, remedial work, damages to natural resources or for personal injury claims (whether under Environmental Laws or otherwise); and (e) no Loan Party otherwise has any known material contingent liability under any Environmental Laws or in connection with the release into the environment, or the storage or disposal, of any Hazardous Materials.

5.13

Borrower’s Subsidiaries

.  The Borrower does not presently have any Subsidiary or own any stock in any other corporation or association except those listed on Schedule 5.13 and except in cases where the Borrower owns less than 5% of the outstanding capital stock of any such corporation. Neither the Borrower nor any Loan Party is a member of any general or limited partnership, limited liability company, joint venture formed under the laws of the United States or any State thereof or association of any type whatsoever except those listed on Schedule 5.13 and associations, joint ventures or other relationships which are established pursuant to a standard form operating agreement or similar agreement or which are partnerships for purposes of federal income taxation only, which are not corporations or partnerships (or subject to the Uniform Partnership Act) under applicable state Law, and whose businesses are limited to the exploration, development and operation of oil, gas or mineral properties, pipelines or gathering systems and interests owned directly by the parties in such associations, joint ventures or relationships. The Borrower owns, directly or indirectly, the equity interests in each of its Subsidiaries which is indicated on Schedule 5.13.

5.14

Title to Properties; Licenses

.  Each Loan Party has good and defensible title to all of its material properties and assets, free and clear of all Liens other than Permitted Liens and of all impediments to the use of such properties and assets in such Loan Party’s business. Each Loan Party possesses all licenses, permits, franchises, patents, copyrights, trademarks and trade names, and other intellectual property (or otherwise possesses the right to use such intellectual property without violation of the rights of any other Person) which are reasonably necessary to carry out its business as presently conducted and as presently proposed to be conducted hereafter, and no Loan Party is in violation in any material respect of the terms under which it possesses such intellectual property or the right to use such intellectual property.

5.15

Government Regulation.

(a)

The Borrower is not engaged and will not engage, principally or as one of its important activities, in the business of purchasing or carrying margin stock (within the meaning of Regulation U issued by the FRB), or extending credit for the purpose of purchasing or carrying margin stock.  Following the application of the proceeds of each Borrowing, not more than 25% of the value of the assets (either of the Borrower only or of the Borrower and its subsidiaries on a consolidated basis) subject to the provision of Section 7.01 or Section 7.09 or subject to any restriction contained in any agreement or instrument between the Borrower and any Lender or any Affiliate of any Lender relating to Indebtedness and within the scope of Section 8.01(g) will be margin stock.

(b)

Neither the Borrower nor any other Loan Party owing Obligations is subject to regulation under the Public Utility Holding Company Act of 1935, the Federal Power Act, the Investment Company Act of 1940 (as any of the preceding acts have been amended) or any other Law which regulates the incurring by such Person of Indebtedness.



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5.16

Solvency

.  Upon giving effect to the issuance of the Notes, the execution of the Loan Documents by the Borrower and the consummation of the transactions contemplated hereby, the Borrower will be solvent (as such term is used in applicable bankruptcy, liquidation, receivership, insolvency or similar Laws).

5.17

Representations by the Borrower relating to Elm Grove Field Acquisition

.  As of the making of Loans to finance all or any part of the purchase price for the Elm Grove Field Acquisition:  

(a)

The Elm Grove Field Acquisition will be consummated substantially concurrently with the making of the Loans for a cash purchase price not to exceed $658,000,000.

(b)

The Borrower has the requisite corporate power and authority to enter into and deliver the Elm Grove Field Acquisition Agreements and to carry out its obligations contemplated thereby.  The execution and delivery of the Elm Grove Field Acquisition Agreements by the Borrower, the performance by the Borrower of its obligations thereunder and the consummation by Borrower of the transactions contemplated thereby have been duly authorized by the Board of Directors of the Borrower.  No other corporate proceedings on the part of the Borrower are necessary to authorize the execution and delivery of the Elm Grove Field Acquisition Agreements, the performance of its obligations thereunder and the consummation by the Borrower of the transactions contemplated thereby.  Each Elm Grove Field Acquisition Agreement has been duly executed and delivered by the Borrower and constitutes a va lid and binding obligation of the Borrower, enforceable in accordance with its terms, except to the extent that its enforceability may be limited by applicable bankruptcy, insolvency, fraudulent transfer, reorganization principles or other laws affecting the enforcement of creditor’s rights generally or by general equitable principles.  

(c)

Neither the execution and delivery of any Elm Grove Field Acquisition Agreement by the Borrower nor the consummation by the Borrower of the transactions contemplated thereby nor compliance by the Borrower with any of the provisions therein will (i) result in a violation or breach of or conflict with its certificate or articles of incorporation or bylaws, (ii) result in a violation or breach of or conflict with any provisions of, or constitute a default (or an event which, with notice or lapse of time or both, would constitute a default) under, or result in the termination, cancellation of, or give rise to a right of purchase under, or accelerate the performance required by, or result in a right of termination or acceleration under, or result in the creation of any Lien upon any of the properties or assets owned or operated by the Borrower or any Subsidiaries under, or result in being de clared void, voidable, or without further binding effect, under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, deed of trust, license, contract, lease, agreement or other instrument or obligation of any kind to which the Borrower or any of the Subsidiaries is a party or by which the Borrower or any of the Subsidiaries or any of their respective properties or assets is bound, or (iii) subject to obtaining or making the consents, approvals, orders, authorizations, registrations, declarations and filings referred to in clause (d) below, violate any judgment, ruling, order, writ, injunction, decree, statute, law (including common law), rule or regulation applicable to the Borrower or any of the Subsidiaries or any of their respective properties or assets.

(d)

No consent, approval, order or authorization of, or registration, declaration or filing with, any Governmental Authority is necessary to be obtained or made by the Borrower or any of its Subsidiaries in connection with the Borrower’s execution, delivery and performance of any Elm Grove Field Acquisition Agreement or the consummation by the Borrower of the transactions contemplated thereby, except for (i) consents, approvals and governmental filings that have been made or obtained prior



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to such date, and (ii) such governmental consents, qualifications or filings as are customarily obtained or made following the transfer of interests in oil and gas properties.

(e)

There is no preliminary injunction or other order, decree or ruling issued by a court of competent jurisdiction or by a Governmental Authority, nor any statute, rule, regulation or executive order promulgated or enacted by any Governmental Authority, in effect that would make the Elm Grove Field Acquisition in contravention of any applicable Law or otherwise prevent the consummation thereof.

ARTICLE VI.
AFFIRMATIVE COVENANTS OF BORROWER

To conform with the terms and conditions under which each Lender is willing to have credit outstanding to the Borrower, and to induce each Lender to enter into this Agreement and extend credit hereunder, the Borrower warrants, covenants and agrees that until the full and final payment of the Obligations and the termination of this Agreement, unless Required Lenders have previously agreed otherwise:

6.01

Payment and Performance

.  The Borrower will pay all amounts due under the Loan Documents in accordance with the terms thereof and will observe, perform and comply with every covenant, term and condition expressed or implied in the Loan Documents. The Borrower will cause each other Loan Party to observe, perform and comply with every such term, covenant and condition in any Loan Document.

6.02

Books, Financial Statements and Reports

.  Each Loan Party will at all times maintain full and accurate books of account and records. The Borrower will maintain and will cause its Subsidiaries to maintain a standard system of accounting, will maintain its fiscal year, and will furnish the following statements and reports to Administrative Agent and each Lender at the Borrower’s expense:

(a)

Within five (5) days after the date required to be delivered to the SEC, but no later than ninety-five (95) days after the end of each fiscal year, complete consolidated financial statements of the Borrower together with all notes thereto, which shall be prepared in reasonable detail in accordance with GAAP and shall not be subject to any “going concern” or like qualification or exception or any qualification or exception as to the scope of such audit, together with an unqualified opinion based on an audit using generally accepted auditing standards, by Ernst & Young LLP or another independent certified public accountant of nationally recognized standing reasonably acceptable to the Required Lenders, stating that such consolidated financial statements have been so prepared. These financial statements shall contain a consolidated balance sheet as of the end of such fiscal y ear and consolidated statements of earnings, of cash flows, and of changes in shareholders’ equity for such fiscal year, each setting forth in comparative form the corresponding figures for the preceding fiscal year. On the date of delivery of such financial statements to Administrative Agent and each Lender, the Borrower will furnish to Administrative Agent and each Lender a Compliance Certificate signed by a Responsible Officer of the Borrower, stating that such financial statements fairly present the financial condition of the Borrower, stating that such Person has reviewed the Loan Documents, containing all calculations required to be made to show compliance or non-compliance with the provisions of Section 7.11, and further stating that there is no condition or event at the end of such fiscal year or at the time of such certificate which constitutes a Default or specifying the nature and period of existence of any such condition or event.



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(b)

Within five (5) days after the date required to be delivered to the SEC, but no later than fifty (50) days after the end of each fiscal quarter, the Borrower’s consolidated balance sheet and income statement as of the end of such fiscal quarter and a consolidated statement of cash flows for the period from the beginning of the then current fiscal year to the end of such fiscal quarter, all in reasonable detail and prepared in accordance with GAAP, subject to changes resulting from normal year-end adjustments. In addition, the Borrower will, together with each such set of financial statements, furnish a Compliance Certificate signed by a Responsible Officer of the Borrower stating that such financial statements are accurate and complete (subject to normal year-end adjustments), stating that such Person has reviewed the Loan Documents, containing all calculations required to be made by the Borrower to show compliance or non­compliance with the provisions of Section 7.11 and further stating that there is no condition or event at the end of such fiscal quarter or at the time of such certificate which constitutes a Default or specifying the nature and period of existence of any such condition or event.

(c)

Promptly upon their becoming available, the Borrower shall provide copies of all registration statements, periodic reports and other statements and schedules filed by any Loan Party with any securities exchange, the SEC or any similar Governmental Authority.

Documents required to be delivered pursuant to Section 6.02(a), (b) or (c) (to the extent any such documents are included in materials otherwise filed with the SEC) may be delivered electronically and if so delivered, shall be deemed to have been delivered on the date (i) on which the Borrower posts such documents, or provides a link thereto on the Borrower’s website on the Internet at the website address listed on Schedule 10.02; or (ii) on which such documents are posted on the Borrower’s behalf on an Internet or intranet website, if any, to which each Lender and the Administrative Agent have access (whether a commercial, third-party website or whether sponsored by the Administrative Agent); provided that: (i) the Borrower shall deliver paper copies of such documents to the Administrative Agent or any Lender that requests the Borrower to de liver such paper copies until a written request to cease delivering paper copies is given by the Administrative Agent or such Lender and (ii) the Borrower shall notify (which may be by facsimile or electronic mail) the Administrative Agent and each Lender of the posting of any such documents and provide to the Administrative Agent by electronic mail electronic versions (i.e., soft copies) of such documents. Notwithstanding anything contained herein, in every instance the Borrower shall be required to provide paper copies of the Compliance Certificates required by Sections 6.02(a) and (b) to the Administrative Agent. Except for such Compliance Certificates, the Administrative Agent shall have no obligation to request the delivery or to maintain copies of the documents referred to above, and in any event shall have no responsibility to monitor compliance by the Borrower with any such request for delivery, and each Lender shall be solely responsible for requesting delivery to it or maintain ing its copies of such documents.

The Borrower hereby acknowledges that (a) the Administrative Agent and/or the Arranger will make available to the Lenders materials and/or information provided by or on behalf of the Borrower hereunder (collectively, “Borrower Materials”) by posting the Borrower Materials on IntraLinks or another similar electronic system (the “Platform”) and (b) certain of the Lenders (each, a “Public Lender”) may have personnel who do not wish to receive material non-public information with respect to the Borrower or its Affiliates, or the respective securities of any of the foregoing, and who may be engaged in investment and other market-related activities with respect to such Persons’ securities.  The Borrower hereby agrees that (w) all Borrower Materials that are to be made available to Public Lenders shall be clearly and conspicuously ma rked “PUBLIC” which, at a minimum, shall mean that the word “PUBLIC” shall appear prominently on the first page thereof; (x) by marking Borrower Materials “PUBLIC,” the Borrower shall be deemed to have authorized the Administrative Agent, the Arranger and the Lenders to treat such Borrower Materials as not containing any material non-public information with respect to the Borrower or its securities for purposes of United States Federal and state securities laws (provided, however, that to the extent such Borrower Materials constitute Information, they shall be



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treated as set forth in Section10.08); (y) all Borrower Materials marked “PUBLIC” are permitted to be made available through a portion of the Platform designated “Public Side Information;” and (z) the Administrative Agent and the Arranger shall be entitled to treat any Borrower Materials that are not marked “PUBLIC” as being suitable only for posting on a portion of the Platform not designated “Public Side Information.”

6.03

Other Information and Inspections

.  The Borrower will furnish to each Lender any information which Administrative Agent or any Lender may from time to time reasonably request concerning any covenant, provision or condition of the Loan Documents or any matter in connection with Loan Parties’ businesses and operations. The Borrower will permit, and will cause the other Loan Parties to permit, representatives appointed by Administrative Agent (including independent accountants, auditors, agents, attorneys, appraisers and any other Persons) to visit and inspect during normal business hours any of the Loan Parties properties, including its books of account, other books and records, and any facilities or other business assets, and to make extra copies therefrom and photocopies and photographs thereof, and to write down and record any information such representatives obtain. The Borrower will permit, and will cause the other Loan Parties to permit, Administrative Agent or any Lender or its representatives to investigate and verify the accuracy of the information furnished to Administrative Agent or any Lender in connection with the Loan Documents and to discuss all such matters with its officers, employees and representatives.

6.04

Notice of Material Events and Change of Address

.  The Borrower will promptly notify each Lender in writing, stating that such notice is being given pursuant to this Agreement, of:

(a)

the occurrence of any event which would have a Material Adverse Effect,

(b)

the occurrence of any Default,

(c)

the acceleration of the maturity of any Indebtedness owed by any Loan Party having a principal balance of more than $35,000,000, or of any default by any Loan Party under any indenture, mortgage, agreement, contract or other instrument to which any of them is a party or by which any of them or any of their properties is bound, if such default would have a Material Adverse Effect,

(d)

the occurrence of any ERISA Event,

(e)

any single claim of $35,000,000 or more, any notice of potential liability under any Environmental Laws which would reasonably be expected to exceed such amount, or any other material adverse claim asserted against any Loan Party or with respect to any Loan Party’s properties,

(f)

the filing of any suit or proceeding against any Loan Party in which an adverse decision would have a Material Adverse Effect,

(g)

any material change in the accounting or financial reporting practices of the Borrower or its Subsidiaries, and

(h)

any announcement by Moody’s or S&P of any change or possible change in Debt Rating.

Upon the occurrence of any of the foregoing, the Loan Parties will take all necessary or appropriate steps to remedy promptly any such Material Adverse Effect, Default, acceleration, default or ERISA Event, to



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protect against any such adverse claim, to defend any such suit or proceeding, and to resolve all controversies on account of any of the foregoing. The Borrower will also notify Administrative Agent and Administrative Agent’s counsel in writing promptly in the event that any Loan Party changes its name or the location of its chief executive office.

6.05

Maintenance of Properties

.  Each Loan Party will maintain, preserve, protect, and keep all property used or useful in the conduct of its business in good condition and in compliance with all applicable Laws in all material respects, and will from time to time make all repairs, renewals and replacements needed to enable the business and operations carried on in connection therewith to be promptly and advantageously conducted at all times in accordance with industry standards.

6.06

Maintenance of Existence and Qualifications

.  Each Loan Party will maintain and preserve its existence and its rights and franchises in full force and effect and will qualify to do business in all states or jurisdictions where required by applicable Law, except where the failure so to qualify will not have a Material Adverse Effect.

6.07

Payment of Trade Liabilities, Taxes, etc.

  Each Loan Party will timely file all required tax returns; timely pay all taxes, assessments, trade liabilities, royalties, and other governmental charges or levies imposed upon it or upon its income, profits or property; and maintain appropriate accruals and reserves for all of the foregoing in accordance with GAAP. Each Loan Party may, however, delay paying or discharging any of the foregoing so long as it is in good faith contesting the validity thereof by appropriate proceedings and has set aside on its books adequate reserves therefor.

6.08

Insurance

.  In accordance with industry standards, each Loan Party will keep or cause to be kept insured or self-insured, at the option of each Loan Party, its surface equipment and other property of a character usually insured by similar Persons engaged in the same or similar businesses. The insurance coverages and amounts will be reasonably determined by each Loan Party, based on coverages carried by prudent owners of similar equipment and property.

6.09

Performance on Borrower’s Behalf

.  If any Loan Party fails to pay any taxes, insurance premiums, expenses, attorneys’ fees or other amounts it is required to pay under any Loan Document during any period in which a Default exists, Administrative Agent may pay the same. The Borrower shall immediately reimburse Administrative Agent for any such payments and each amount paid by Administrative Agent shall constitute an Obligation owed hereunder which is due and payable on the date such amount is paid by Administrative Agent.

6.10

Interest

.  The Borrower hereby promises to Administrative Agent and each Lender to pay interest at the Default Rate applicable to Base Rate Loans on all Obligations (including Obligations to pay fees or to reimburse or indemnify any Lender) which the Borrower has in this Agreement promised to pay to



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Administrative Agent and Lenders and which are not paid when due. Such interest shall accrue from the date such Obligations become due until they are paid.

6.11

Compliance with Agreements and Law

.  Each Loan Party will perform all material obligations it is required to perform under the terms of each indenture, mortgage, deed of trust, security agreement, lease, franchise, agreement, contract or other instrument or obligation to which it is a party or by which it or any of its properties is bound. Each Loan Party will conduct its business and affairs in compliance with all Laws applicable thereto.

6.12

Environmental Matters.

(a)

Except as otherwise set forth in Schedule 5.12, each Loan Party will comply in all material respects with all Environmental Laws now or hereafter applicable to such Loan Party, as well as all contractual obligations and agreements with respect to environmental remediation or other environmental matters, and shall obtain, at or prior to the time required by applicable Environmental Laws, all environmental, health and safety permits, licenses and other authorizations necessary for its operations and will maintain such authorizations in full force and effect.

(b)

The Borrower will promptly furnish to Administrative Agent all written notices of violation, orders, claims, citations, complaints, penalty assessments, suits or other proceedings received by the Borrower, or of which it has notice, pending or threatened against the Borrower, by any Governmental Authority with respect to any alleged violation of or non-compliance with any Environmental Laws or any permits, licenses or authorizations in connection with its ownership or use of its properties or the operation of its business, if the violation, order, claim, citation, complaint, penalty assessment, suit or other proceeding could reasonably be expected to result in liability to the Borrower in excess of $35,000,000.

(c)

The Borrower will promptly furnish to Administrative Agent all requests for information, notices of claim, demand letters, and other notifications, received by the Borrower in connection with its ownership or use of its properties or the conduct of its business, relating to potential responsibility with respect to any investigation or clean-up of Hazardous Material at any location which could reasonably be expected to result in a liability to the Borrower in excess of $35,000,000.

6.13

Evidence of Compliance

.  Each Loan Party will furnish to each Lender at such Loan Party’s or the Borrower’s expense all evidence which Administrative Agent from time to time reasonably requests in writing as to the accuracy and validity of or compliance with all representations, warranties and covenants made by any Loan Party in the Loan Documents, the satisfaction of all conditions contained therein, and all other matters pertaining thereto.

6.14

Use of Proceeds

.  The Borrower will use the proceeds of the Loans to finance the Acquisitions and to pay transaction costs and expenses associated therewith.

6.15

Subordination of Intercompany Indebtedness

.  From and after the date of the initial Borrowing under this Agreement, all indebtedness, liabilities and obligations of the Borrower to Questar Corporation or to any Restricted Subsidiary shall be



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subordinated to the Obligations pursuant to the terms of a Subordination Agreement substantially in the form of Exhibit F (with such changes as the Administrative Agent shall approve), executed by Questar Corporation (or the applicable Restricted Subsidiary) and the Borrower and delivered to the Administrative Agent.

ARTICLE VII.
NEGATIVE COVENANTS OF BORROWER

To conform with the terms and conditions under which each Lender is willing to have credit outstanding to the Borrower, and to induce each Lender to enter into this Agreement and make the Loans, the Borrower warrants, covenants and agrees that until the full and final payment of the Obligations and the termination of this Agreement, unless Required Lenders have previously agreed otherwise:

7.01

Indebtedness

.  No Restricted Subsidiary will in any manner owe or be liable for Indebtedness except:

(a)

the Obligations;

(b)

capital lease obligations (excluding oil, gas or mineral leases) entered into in the ordinary course of such Restricted Subsidiary’s business in arm’s length transactions at competitive market rates under competitive terms and conditions in all respects, provided that the obligations required to be paid in any fiscal year under any such capital leases do not in the aggregate exceed $2,000,000 for all Restricted Subsidiaries;

(c)

unsecured Indebtedness owed by the Restricted Subsidiaries (i) to the Borrower or (ii) to Questar Corporation or (iii) to another Restricted Subsidiary, provided that from and after the date of the initial Borrowing under this Agreement (x) the aggregate principal amount of Indebtedness of the Restricted Subsidiaries to Questar Corporation shall not exceed $250,000,000 and (y) all Indebtedness of the Restricted Subsidiaries to Questar Corporation shall be subject to a Subordination Agreement executed by Questar Corporation, the applicable Restricted Subsidiary and the Borrower and delivered to Administrative Agent substantially in the form of Exhibit F (with such changes as the Administrative Agent shall approve);

(d)

[intentionally omitted];

(e)

Indebtedness of the Restricted Subsidiaries for plugging and abandonment bonds issued by third parties or for letters of credit issued in place thereof which are required by regulatory authorities in the area of operations, and Indebtedness of the Restricted Subsidiaries for other bonds or letters of credit which are required by such regulatory authorities with respect to other normal oil and gas operations;

(f)

non-recourse Indebtedness as to which no Loan Party (i) provides any guaranty or credit support of any kind (including any undertaking, guarantee, indemnity, agreement or instrument that would constitute Indebtedness) or (ii) is directly or indirectly liable (as a guarantor or otherwise); provided, that after giving effect to such Indebtedness outstanding from time to time, the Borrower is not in violation of Section 7.11;

(g)

Indebtedness that is subordinated to the Obligations on terms acceptable to Required Lenders;



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(h)

Acquired Debt which meets the following requirements: (i) the documentation evidencing such Indebtedness shall contain no terms, conditions or defaults (other than pricing) which are more favorable to the third party creditor than those contained in this Agreement are to Lenders and (ii) at the time such Indebtedness is incurred, no Default shall have occurred and be continuing hereunder;

(i)

Indebtedness under Swap Contracts permitted under Section 7.10; and

(j)

unsecured Indebtedness of the Restricted Subsidiaries not described in subsections (a) through (i) above which meets the following requirements: (i) the documentation evidencing such Indebtedness shall contain no terms, conditions or defaults (other than pricing) which are more favorable to the third party creditor than those contained in this Agreement are to Lenders and (ii) at the time such Indebtedness is incurred, no Default shall have occurred and be continuing hereunder; provided that the Indebtedness of the Restricted Subsidiaries permitted under this subsection (j) shall not exceed $30,000,000 in the aggregate.

7.02

Limitation on Liens

.  Except for Permitted Liens, no Loan Party will create, assume or permit to exist any Lien upon any of the properties or assets which it now owns or hereafter acquires. No Loan Party will allow the filing or continued existence of any financing statement describing as collateral any assets or property of such Loan Party, other than financing statements which describe only collateral subject to a Lien permitted under this Section and which name as secured party or lessor only the holder of such Lien.

7.03

Limitation on Investments and New Businesses

.  No Loan Party will:

(a)

engage directly or indirectly in any business or conduct any operations, except (i) in connection with or incidental to its present businesses and operations or complementary to such businesses or operations or (ii) in connection with businesses or operations that are not material to the Borrower and its Subsidiaries on a consolidated basis; or

(b)

make any acquisitions of or capital contributions to any Person or any other Investment, except (i) Acquisitions, the purchase price for which is funded by Loans made under this Agreement, (ii) Investments in the ordinary course of business, (iii) purchases of equity interests in Persons involved in the oil and gas industry if the aggregate amount of the purchase price for all such purchases (including the purchase in question) made by the Loan Parties after the date hereof does not exceed $50,000,000, and (iv) mergers permitted under Section 7.04.

7.04

Limitation on Mergers

.  The Borrower will not (i) merge or consolidate with or into any other Person unless the Borrower is the surviving business entity and no Default exists prior to such merger or consolidation or will exist immediately thereafter or (ii) Dispose of (whether in one transaction or in a series of transactions) all or substantially all of its assets (whether now owned or hereafter acquired) to or in favor of any Person.

7.05

Limitation on Issuance of Securities by Subsidiaries of Borrower