Attached files

file filename
EX-24 - POWER OF ATTORNEY - QEP RESOURCES, INC.dex24.htm
EX-32.1 - CERTIFICATION SIGNED BY CHARLES B. STANLEY AND RICHARD J. DOLESHEK - QEP RESOURCES, INC.dex321.htm
EX-31.1 - CERTIFICATION SIGNED BY CHARLES B. STANLEY, QEP RESOURCES, INC. - QEP RESOURCES, INC.dex311.htm
EX-21.1 - SUBSIDIARIES OF THE COMPANY - QEP RESOURCES, INC.dex211.htm
EX-23.3 - QUALIFICATIONS AND REPORT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS - QEP RESOURCES, INC.dex233.htm
EX-23.2 - CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS - QEP RESOURCES, INC.dex232.htm
EX-23.1 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - QEP RESOURCES, INC.dex231.htm
EX-12.1 - RATIO OF EARNINGS TO FIXED CHARGES - QEP RESOURCES, INC.dex121.htm
EX-31.2 - CERTIFICATION SIGNED BY RICHARD J. DOLESHEK, QEP RESOURCES, INC. - QEP RESOURCES, INC.dex312.htm
Table of Contents

 

 

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, 2010

LOGO

 

 

QEP RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

STATE OF DELAWARE   001-34778   87-0287750

(State or other jurisdiction of

incorporation)

  (Commission File No.)  

(I.R.S. Employer

Identification No.)

1050 17th Street, Suite 500, Denver, Colorado 80265

(Address of principal executive offices)

Registrant’s telephone number, including area code: 303-672-6900

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

 

Title of each class

 

Name of each exchange on which registered

Common stock, $0.01 par value   New York Stock Exchange

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

 

 

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    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.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   ¨      Accelerated filer   ¨
Non-accelerated filer   x   (Do not check if a smaller reporting company)    Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. (June 30, 2010): $0.

At February 18, 2011, there were 176,305,256 shares of the registrant’s $0.01 par value common stock outstanding.

 

 

DOCUMENTS INCORPORATED BY REFERENCE

Part III is incorporated by reference from the registrant’s Definitive Proxy Statement for its 2011 Annual Meeting of Stockholders to be filed, pursuant to Regulation 14A, no later than 120 days after the close of the registrant’s fiscal year.

 

 

 


Table of Contents

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

     8   
  

Nature of Business

     8   
  

Exploration and Production – QEP Energy Company

     9   
  

Midstream Field Services – QEP Field Services Company

     10   
  

Energy Marketing – QEP Marketing Company

     11   
  

Employees

     11   
  

Executive Officers

     12   
Item 1A.   

RISK FACTORS

     13   
Item 1B.   

UNRESOLVED STAFF COMMENTS

     20   
Item 2.   

PROPERTIES

     21   
  

Exploration and Production – QEP Energy Company

     21   
  

Midstream Field Services – QEP Field Services Company

     24   
  

Energy Marketing – QEP Marketing Company

     24   
Item 3.   

LEGAL PROCEEDINGS

     25   
Item 4.   

REMOVED AND RESERVED

     25   
   PART II   
Item 5.   

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

     26   
Item 6.   

SELECTED FINANCIAL DATA

     28   
Item 7.   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

  

 

30

  

Item 7A.   

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     45   
Item 8.   

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     47   
Item 9.   

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

  

 

87

  

Item 9A.   

CONTROLS AND PROCEDURES

     87   
Item 9B.   

OTHER INFORMATION

     89   

 

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          Page No.  
   PART III   
Item 10.   

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

     89   
Item 11.   

EXECUTIVE COMPENSATION

     89   
Item 12.   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

     89   
Item 13.   

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

     89   
     
Item 14.   

PRINCIPAL ACCOUNTING FEES AND SERVICES

     89   
   PART IV   
Item 15.   

EXHIBITS, FINANCIALS STATEMENT SCHEDULES

     90   
  

SIGNATURES

     94   

 

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Where You Can Find More Information

QEP Resources, Inc. (QEP or the Company) files annual, quarterly, and current reports with the Securities and Exchange Commission (SEC). Prior to QEP’s Spin-off from Questar Corporation (described in more detail in the Explanatory Note in Item 1 of Part I of this Annual Report on Form 10-K), QEP’s predecessor, Questar Market Resources, Inc., filed annual, quarterly and current reports with the SEC. QEP also regularly files proxy statements and other documents with the SEC. These reports and other information can be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549-0213. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC also maintains an internet site at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including QEP.

Investors can also access financial and other information via QEP’s website at www.qepres.com. QEP makes available, free of charge through the website copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to such reports and all reports filed by executive officers and directors under Section 16 of the Exchange Act reporting transactions in QEP securities. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC. Information contained on or connected to QEP’s website which is not directly incorporated by reference into the Company’s Annual Report on Form 10-K should not be considered part of this report or any other filing made with the SEC.

QEP’s website also contains copies of charters for various board committees, including the Audit Committee, Corporate Governance Guidelines and QEP’s Business Ethics and Compliance Policy.

Finally, you may request a copy of filings other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing or calling QEP, 1050 17th Street, Suite 500, Denver, CO 80265 (telephone number: 1-303-672-6900).

Forward-Looking Statements

This Annual Report contains or incorporates 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. Forward-looking statements include statements relating to, among other things:

 

   

plans to drill or participate in wells;

 

   

expenses;

 

   

the outcome of contingencies such as legal proceedings;

 

   

trends in operations;

 

   

forecasted capital expenditures for 2011;

 

   

the importance of adjusted EBITDA as a measure of cash flow and liquidity;

 

   

the ability of QEP to use derivative instruments to manage commodity price risk;

 

   

acquisition plans;

 

   

growth strategy;

 

   

climate change; and

 

   

the impact of regulatory changes on exploration and development costs;

 

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Any or all forward-looking statements may turn out to be incorrect. 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. Factors that could cause actual results to differ materially include, but are not limited to the following:

 

   

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

 

   

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

 

   

changes in industry trends;

 

   

changes in laws or regulations; and

 

   

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

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

Glossary of Commonly Used Terms

B  Billion.

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

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

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 Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 815 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 or feet 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 foot or feet of natural gas equivalents.

developed reserves  Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. See 17 C.F.R. Section 4-10(a)(6).

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

 

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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.

equity production  Production at the wellhead attributed to QEP’s 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 natural gas liquids (NGL) extracted from the natural gas stream and the market value of the Btu-equivalent volume of natural gas required to replace the extracted liquids.

futures contract  A 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 commodity and interest-rate derivative instruments to reduce financial exposure to commodity price and interest-rate volatility.

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 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 is entitled to receive.

NYMEX  The New York Mercantile Exchange.

proved reserves  Those quantities of natural gas, oil, condensate and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. See 17 C.F.R. Section 4-10(a)(22).

reserves  Estimated remaining quantities of natural gas, oil and related substances anticipated to be economically producible by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce. See 17 C.F.R. Section 4-10(a)(26).

 

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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 a gas and oil lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the minerals 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 data/survey  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.

T  Trillion.

undeveloped reserves  Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. See 17 C.F.R. Section 4-10(a)(31).

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

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

 

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FORM 10-K

ANNUAL REPORT 2010

PART I

ITEM 1. BUSINESS

Nature of Business

QEP Resources, Inc. (QEP or the Company), is an independent natural gas and oil exploration and production company. QEP is a holding company with three major lines of business – gas and oil exploration and production, midstream field services, and energy marketing – which are conducted through three principal subsidiaries:

 

   

QEP Energy Company (QEP Energy) acquires, explores for, develops and produces natural gas, oil, and natural gas liquids (NGL);

 

   

QEP Field Services Company (QEP Field Services) provides midstream field services including natural gas gathering, processing and treating services for affiliates and third parties; and

 

   

QEP Marketing Company (QEP Marketing) markets equity and third-party natural gas and oil, provides risk-management services, and owns and operates an underground gas-storage reservoir.

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

The corporate-organization structure and principal subsidiaries are depicted below:

LOGO

EXPLANATORY NOTE

Effective May 18, 2010, Questar Market Resources, Inc., (Market Resources) then a wholly-owned subsidiary of Questar Corporation (Questar), merged with and into a newly-formed, wholly-owned subsidiary, QEP Resources, Inc., a Delaware corporation in order to reincorporate in the State of Delaware (Reincorporation Merger). The Reincorporation Merger was effected pursuant to an Agreement and Plan of Merger entered into between Market Resources and QEP. The Reincorporation Merger was approved by the boards of directors of Market Resources and QEP and submitted to a vote of, and approved by, the Board of Directors of Questar, as sole shareholder of Market Resources, and by Market Resources, as sole shareholder of QEP on May 18, 2010.

On June 30, 2010, Questar distributed all of the shares of common stock of QEP held by Questar to Questar shareholders in a tax-free, pro rata dividend (the Spin-off). Each Questar shareholder received one share of QEP

 

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common stock for each one share of Questar common stock held (including fractional shares) at the close of business on the record date. In connection therewith, QEP distributed Wexpro Company (Wexpro), a wholly-owned subsidiary of QEP at the time, to Questar. In addition, Questar contributed $250.0 million of equity to QEP prior to the Spin-off.

In connection with the reorganization, QEP renamed its subsidiaries as follows:

 

   

QEP Energy Company (formerly Questar Exploration and Production Company),

 

   

QEP Field Services Company (formerly Questar Gas Management Company), and

 

   

QEP Marketing Company (formerly Questar Energy Trading Company).

The financial information presented in this Form 10-K presents QEP’s financial results as an independent company separate from Questar and reflects Wexpro’s financial condition and operating results as discontinued operations for all periods presented. A summary of discontinued operations can be found in Note 3 to the consolidated financial statements in Item 8 of this Annual Report on Form 10-K.

EXPLORATION AND PRODUCTION – QEP Energy Company

General: QEP’s exploration and production business is conducted through QEP Energy, which generated approximately 72% of the Company’s operating income in 2010. QEP Energy operates in two core regions – the Rocky Mountain region (including the states of Wyoming, Utah, Colorado, New Mexico and North Dakota) and the Midcontinent region (including the states of Oklahoma, Texas and Louisiana). QEP Energy reported production of 229.0 Bcfe compared to 189.5 Bcfe in 2009. The Midcontinent region contributed approximately 53% of 2010 production while the Rocky Mountain region contributed the remaining 47%. QEP Energy reported 3,030.7 Bcfe of estimated proved reserves as of December 31, 2010, of which approximately 61%, or 1,860.2 Bcfe, were located in the Rocky Mountain region, while the remaining 39%, or 1,170.5 Bcfe, were located in the Midcontinent region. Approximately 53% of the proved reserves reported by QEP Energy at year-end 2010 were developed, while 47% were categorized as proved undeveloped. Natural gas comprised about 86% of the total proved reserves at year-end 2010. The SEC amended its definitions of oil and natural gas reserves effective December 31, 2009. Key revisions impacting the Company include a change in the pricing used to determine estimated proved reserves from year-end prices to first-of-the-month prior 12-month average prices, changes in reserve category definitions, and the allowance of the application of reliable technologies in the determination of proved reserves. See Item 2 of Part I and Note 16 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for more information on the Company’s proved reserves.

QEP Energy has a large inventory of identified development drilling locations, primarily on the Pinedale Anticline in western Wyoming, in northwestern Louisiana, in western Oklahoma and in western North Dakota. QEP Energy continues to conduct exploratory drilling to determine the commerciality of its inventory of undeveloped leaseholds. The Company seeks to acquire, develop and produce natural gas and oil from so-called “resource plays” in its core areas. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations in tight sand, shale and coal reservoirs. Since the existence and distribution of hydrocarbons in resource plays is well understood, development of these accumulations has lower exploration risk than conventional discrete hydrocarbon accumulations. Resource plays typically require many wells, drilled at high density, to fully develop and produce the hydrocarbon accumulations. Development of QEP Energy’s resource play accumulations requires expertise in drilling large numbers of complex, highly deviated or horizontal wells to depths in excess of 13,000 feet and the application of advanced well completion techniques, including hydraulic fracture stimulation, to achieve economic production. QEP Energy seeks to maintain geographical and geological diversity with its two core regions. The Company has in the past and may in the future pursue acquisition of producing properties through the purchase of assets or corporate entities to expand its presence in its core areas or to create new core areas.

 

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Competition and Customers: QEP Energy faces competition in every part of its business, including the acquisition of producing properties and undeveloped leasehold, the marketing of natural gas and oil, and obtaining goods, services and labor. Its longer-term growth strategy depends, in part, on its ability to acquire reasonably-priced acreage containing reserves and identify and develop them in a low-cost and efficient manner.

QEP Energy, both directly and through QEP Marketing, sells natural gas production to a variety of customers, including gas-marketing firms, industrial users and local-distribution companies. QEP Energy regularly evaluates counterparty credit and may require financial guarantees or prepayments from parties that fail to meet its credit criteria.

Regulation: QEP Energy operations are subject to various government controls and regulation at the federal, state and local levels. QEP Energy must obtain permits to drill and produce wells; maintain required bonds 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 drilling, completion and production. QEP Energy is also subject to various conservation matters, including the regulation of the size of drilling and spacing units, the number of wells that may be drilled in a unit and the unitization or pooling of gas and oil properties.

Most of QEP Energy’s leasehold acreage in the Rocky Mountain region is held under leases granted by the United States and administered by federal agencies, principally the Bureau of Land Management (BLM). Current federal regulations restrict activities during certain times of the year on significant portions of QEP Energy leasehold due to wildlife activity and/or habitat. QEP Energy has worked with federal and state officials in Wyoming to obtain authorization for limited winter-drilling activities on the Pinedale Anticline and has developed measures, such as drilling multiple wells from a single pad location, to minimize the impact of its activities on wildlife and wildlife habitat. Various wildlife species inhabit QEP Energy leaseholds at Pinedale and in other areas. The presence of wildlife or plants, including species and types that are protected under the federal Endangered Species Act, could limit access to leases held by QEP Energy on public lands.

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

MIDSTREAM FIELD SERVICES – QEP Field Services Company

General: QEP Field Services generated approximately 27% of the Company’s operating income in 2010. QEP Field Services owns various natural gas gathering, treating and processing facilities in the Rocky Mountain and Midcontinent regions as well as 78% of Rendezvous Gas Services, LLC, (RGS), a partnership that operates gas gathering facilities in western Wyoming. QEP Field Services also owns 38% of Uintah Basin Field Services, LLC (UBFS) and 50% of Three Rivers Gathering, LLC (Three Rivers). These partnerships operate natural gas gathering facilities in eastern Utah. The FERC-regulated Rendezvous Pipeline Co., LLC (Rendezvous Pipeline), a wholly owned subsidiary of QEP Field Services, operates a 21-mile, 20-inch-diameter pipeline between QEP Field Services’ Blacks Fork gas-processing plant and the Muddy Creek compressor station owned by Kern River Gas Transmission Co. (Kern River Pipeline). RGS gathers natural gas for Pinedale Anticline and Jonah Field producers for delivery to various interstate pipelines.

Fee-based gathering and processing revenues were 78% of QEP Field Services’ net operating revenues (revenues less plant shrink) during 2010. Approximately 36% of QEP Field Services’ 2010 net gas-processing revenues (processing revenues less plant shrink) were derived from fee-based processing agreements. The remaining revenues were derived from keep-whole processing agreements. A keep-whole contract exposes QEP Field Services to frac-spread risk while a fee-based contract eliminates commodity price exposure. To further reduce volatility associated with keep-whole contracts, QEP Field Services 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.

 

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Competition and Customers: QEP faces regional competition with varying competitive factors in each basin. QEP’s gathering and processing business competes with other midstream companies, interstate and intrastate pipelines, producers and independent gatherers and processors. Numerous factors impact a customer’s choice of a gathering or processing services provider, including rate, location, term, pressure obligations, timeliness of services, and contract structure. QEP Field Services provides natural gas gathering, processing and treating services to affiliates and third-party producers who own producing natural gas fields in the Rocky Mountain region and in northwest Louisiana. Most of QEP Field Services’ gas gathering, processing and treating services are provided under long-term agreements.

ENERGY MARKETING—QEP Marketing Company

General: QEP Marketing provides wholesale marketing and sales of affiliate and third-party natural gas, oil and NGL and generated approximately 1% of the Company’s operating income in 2010. As a wholesale marketing entity, QEP Marketing 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. QEP Marketing contracts for firm-transportation capacity on pipelines and firm-storage capacity at Clay Basin, a large baseload-storage facility. QEP Marketing, through its subsidiary Clear Creek Storage Company, LLC, operates an underground gas-storage reservoir in southwestern Wyoming. QEP Marketing uses owned and leased storage capacity together with firm-transportation capacity to manage seasonal swings in prices in the Rocky Mountain region.

Competition and Customers: QEP Marketing competes directly with large independent energy marketers, marketing affiliates of regulated pipelines and utilities and natural gas producers. QEP Marketing also competes with brokerage houses, energy hedge funds and other energy-based companies offering similar services. QEP Marketing sells QEP Energy natural gas and volumes purchased from third parties to wholesale marketers, industrial end-users and utilities. QEP Marketing sells QEP Energy crude oil volume to refiners, remarketers and other companies, including some with pipeline facilities near company producing properties. In the event pipeline facilities are not available, QEP Marketing arranges transportation of crude oil by truck or rail to storage, refining or pipeline facilities. QEP Marketing uses derivative instruments to manage commodity price risk, primarily fixed-price swaps to secure a known price for a specific volume of production. QEP Marketing does not engage in speculative hedging transactions. See Item 7A and Notes 1 and 7 to the consolidated financial statements included in Item 8 of Part II of this Annual Report for additional information relating to hedging activities.

Employees

At December 31, 2010, QEP Resources, Inc. had 823 employees, including 603 in QEP Energy, 198 in QEP Field Services and 22 in QEP Marketing.

 

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Executive Officers of the Registrant

Primary Positions Held with the Company

and Affiliates, Other Business Experience

 

Charles B. Stanley    52    President, Chief Executive Officer, QEP (2010 to present). Previous titles with Questar: Chief Operating Officer (2008 to 2010); Executive Vice President and Director (2003 to 2010); President, Chief Executive Officer and Director, Market Resources and Market Resources subsidiaries (2002 to 2010).
Richard J. Doleshek    52    Executive Vice President and Chief Financial Officer, QEP (2010 to present). Previous titles with Questar: Executive Vice President and Chief Financial Officer (2009 to 2010). Prior to joining Questar, Mr. Doleshek was Executive Vice President and Chief Financial Officer, Hilcorp Energy Company (2001 to 2009).
Jay B. Neese    52    Executive Vice President, QEP (2010 to present). Previous titles with Questar: Senior Vice President (2005 to 2010); Executive Vice President, Market Resources and Market Resources subsidiaries (2005 to 2010); Vice President, Market Resources and Market Resources subsidiaries (2003 to 2005); Assistant Vice President (2001 to 2003).
Perry H. Richards    50    Senior Vice President – Field Services (2010 to present). Previous title with Questar: Vice President, Questar Gas Management (2005 to 2010).
Eric L. Dady    56    Vice President and General Counsel, QEP (2010 to present). Previous title with Questar: General Counsel Market Resources (2005 to 2010).
Abigail L. Jones    50    Vice President, Compliance, Corporate Secretary and Assistant General Counsel, QEP (2010 to present). Previous titles with Questar: Vice President Compliance (2007 to 2010); Corporate Secretary (2005 to 2010); Assistant Secretary (2004 to 2005).

There is no “family relationship” between any of the listed officers or between any of them and the Company’s directors. The executive officers serve at the pleasure of the Board of Directors. There is no arrangement or understanding under which the officers were selected.

 

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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 volatile, and a decline in such prices could adversely affect QEP’s results, stock price and growth plans. Historically natural gas, oil and NGL prices have been volatile and will likely continue to be volatile in the future. U.S. natural gas prices in particular are significantly influenced by weather. Any significant or extended decline in commodity prices would impact the Company’s future financial condition, revenue, operating results, cash flow, return on invested capital, and rate of growth. In addition, significant and extended declines in commodity prices could limit QEP’s access to sources of capital or cause QEP to delay or postpone some of its capital projects. Because a significant portion of QEP Energy’s future production is natural gas, the Company’s financial results are substantially more sensitive to changes in natural gas prices than to changes in oil prices.

QEP 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;

 

   

the potential long-term impact of an abundance of natural gas from unconventional sources on the global gas supply;

 

   

domestic political developments;

 

   

weather conditions;

 

   

domestic government regulations and taxes;

 

   

technological advances affecting energy consumption and energy supply;

 

   

conservation efforts;

 

   

the price, availability and acceptance of alternative fuels;

 

   

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

 

   

the quality of natural gas and oil produced.

In addition, lower commodity prices may result in asset impairment charges from reductions in the carrying values of QEP’s natural gas and oil properties.

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 initial 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.

 

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

Investors should not assume that QEP’s presentation of the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves in this Annual Report is the current market value of the estimated natural gas and oil reserves. In accordance with SEC disclosure rules, the estimated discounted future net cash flows from QEP’s proved reserves are based on the first-of-the-month prior 12-month average prices and current costs on the date of the estimate, holding the prices and costs constant throughout the life of the properties and using a discount factor of 10 percent per year. 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 similarly determined prices and costs may be significantly different from the current estimate.

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

Operations involve numerous risks that might result in accidents and other operating risks and costs. Drilling of natural gas and oil wells is potentially a high-risk activity. Risks include:

 

   

fire, explosions and blow-outs;

 

   

unexpected drilling conditions such as abnormally pressured formations;

 

   

pipe, cement or casing failures;

 

   

pipeline accidents and failures; and

 

   

environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine water or well fluids (including groundwater contamination).

The Company could incur substantial losses as a result of injury or loss of life; pollution or other environmental damage; damage to or destruction of property and equipment; regulatory investigation; fines or curtailment of operations; or attorney’s fees and other expenses incurred in the prosecution or defense of litigation. As a working interest owner in wells operated by other companies, the Company may also be exposed to the risks enumerated above that are not within its care, custody or control.

There are also inherent operating risks and hazards in the Company’s gas and oil production and gas gathering, processing and treating operations that could cause substantial financial losses. In addition, these risks could result in personal injury or loss of human life, significant damage to property, environmental pollution,

 

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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 lost business activity. Such circumstances could adversely impact the Company’s ability to meet contractual obligations.

As is customary in the gas and oil industry, the Company maintains insurance against some, but not all, of these potential risks and losses. Although QEP believes the coverages and amounts of insurances that it carries are adequate and consistent with industry practice, QEP does not have insurance protection against all risks that it faces, because QEP chooses not to insure certain risks, insurance is not available at a level that balances the costs of insurance and QEP’s desired rates of return, or actual losses exceed coverage limits. Losses and liabilities arising from uninsured or underinsured events could have a material adverse effect on QEP’s financial condition, results of operations and cash flows.

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

QEP is dependent on its revolving credit facility and continued access to capital markets to successfully execute its operating strategies. If QEP is unable to obtain needed capital or financing on satisfactory terms, QEP may experience a decline in its natural gas and oil reserves. QEP is partially dependent on external capital sources to provide financing for certain projects. The availability and cost of these capital sources is cyclical, and these capital sources may not remain available, or the Company may not be able to obtain financing at a reasonable cost in the future. Over the last few years, conditions in the global capital markets have deteriorated, making terms for certain financings less attractive, and in certain cases, resulting in the unavailability of certain types of financing. If QEP’s revenues decline as a result of lower natural gas, oil and NGL prices, operating difficulties, declines in production or for any other reason, QEP may have limited ability to obtain the capital necessary to sustain its operations at current levels. The Company utilizes its revolving credit facility, provided by a group of financial institutions, to meet short-term funding needs. All of QEP’s debt under its revolving credit facility is floating-rate debt. From time to time, the Company may use interest-rate derivatives to fix the rate on a portion of its floating-rate debt. The interest rates on debt under the Company’s revolving credit facility are tied to QEP’s debt ratings which are published by Standard & Poor’s and Moody’s. Under QEP’s revolving credit agreement, a downgrade of credit ratings will increase the interest cost of borrowings under the revolving credit facility. In addition, a downgrade of credit ratings may make it more difficult or expensive to raise capital from financial institutions or other sources. QEP’s failure to obtain additional financing could result in a curtailment of its operations relating to exploration and development of its prospects, which in turn could lead to a possible reduction in QEP’s natural gas or oil reserves and its revenues, and could negatively impact its results of operations.

QEP is exposed to counterparty credit risk as a result of QEP’s receivables and commodity derivative transactions. QEP has significant credit exposure to outstanding accounts receivable from joint interest and working interest owners as well as customers in all segments of its business. Because QEP is the operator on a majority of its large joint venture development projects, QEP pays joint venture expenses and makes cash calls on its non-operating partners for their respective shares of joint venture costs. These projects are capital intensive and, in some cases, a non-operating partner may experience a delay in obtaining financing for its share of the joint venture costs. Counterparty liquidity problems could result in a delay in QEP receiving proceeds from commodity sales or reimbursement of joint venture costs. Credit enhancements, such as financial guarantees or prepayments, have been obtained from some but not all parties. Nonperformance by a trade creditor or joint

 

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venture partner could result in financial losses. In addition, QEP’s commodity derivative transactions expose it to risk of financial loss if a counterparty fails to perform under a contract. During periods of falling commodity prices, QEP’s hedge receivable positions increase, which increases its counterparty exposure.

Risks Related to Strategy

QEP’s use of derivative instruments to manage exposure to uncertain prices could result in financial losses or reduce its income. QEP 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 may forgo some or all of the benefits of commodity price increases. Additionally, there are proposed financial regulations which may change our reporting and margining requirements relating to such instruments.

QEP enters into commodity-price derivative arrangements with creditworthy counterparties (banks and energy-trading firms) that do not require collateral deposits. QEP is exposed to the risk of counterparties not performing. The amount of credit available may vary depending on the credit ratings assigned to the Company’s debt securities.

QEP faces significant competition and certain of its competitors have resources in excess of QEP’s available resources. QEP operates in the highly competitive areas of natural gas and oil exploration, exploitation, acquisition and production. QEP faces intense competition from:

 

   

large multi-national, integrated oil companies;

 

   

US independent oil and gas companies;

 

   

service companies engaging in oil and gas exploration and production activities; and

 

   

private oil and gas equity funds.

QEP faces competition in a number of areas such as:

 

   

acquiring desirable producing properties or new leases for future exploration;

 

   

marketing its natural gas, oil and NGL production;

 

   

acquiring the equipment and expertise necessary to operate and develop properties; and

 

   

attracting and retaining employees with certain skills.

Certain of QEP’s competitors have financial and other resources in excess of those available to QEP. Such companies may be able to pay more for seismic and lease rights on natural gas and oil properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than QEP’s financial or human resources permit. This highly competitive environment could have an adverse impact on QEP’s business.

QEP may be subject to risks in connection with acquisitions and organizational changes. 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. QEP may not be able to identify attractive acquisition opportunities. Even if QEP does identify attractive opportunities, it may not be able to complete the acquisitions due to capital constraints. If QEP acquires an additional business, QEP could have difficulty integrating the operations, systems, management and other personnel and technology of the acquired business with QEP’s own, or could assume unidentified or unforeseeable liabilities, resulting in a loss of value.

 

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Organizational modifications due to acquisitions, divestitures or other strategic changes can alter the risk and control environments, disrupt ongoing business, distract management and employees, increase expenses and adversely affect results of operations. Even if these challenges can be dealt with successfully, the anticipated benefits of any acquisition, divestiture or other strategic change may not be realized.

Failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provide absolute assurance that all control issues and instances of fraud, if any, in our Company have been detected. The design of any system of controls is based in part upon the likelihood of future events, and there can be no assurance that any design will succeed in achieving its intended goals under all potential future conditions. Over time, a control may become inadequate because of changes in conditions or the degree of compliance with its policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection.

Risks Related to Regulation

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

QEP must comply with numerous and complex federal and state regulations governing activities on federal and state lands, notably the National Environmental Policy Act, the Endangered Species Act, the Clean Air Act, and the National Historic Preservation Act and similar state laws. The United States Fish and Wildlife Service may designate critical habitat areas for certain listed threatened or endangered species. A critical habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. The listing of certain species, such as the sage grouse, as threatened and endangered, could have a material impact on the Company’s operations in areas where such species are found. The Clean Water Act and similar state laws regulate discharges of storm water, wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and other costs and damages. These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil.

Federal and state regulatory 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 leasehold. Certain environmental groups oppose drilling on some of QEP’s federal and state leases. These groups sometimes sue federal and state regulatory agencies for alleged procedural violations in an attempt to stop, limit or delay natural gas and oil development on public lands.

In addition, the Company is subject to federal and state hazard communications and community right-to-know statutes and regulations such as the Emergency Planning and Community Right-to-Know Act that require certain record keeping and reporting of the use and release of hazardous substances.

 

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Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Land Management and the Bureau of Indian Affairs, along with potentially 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, under prevailing legal precedent each Native American tribe has limited attributes of sovereignty including the right to enforce laws and regulations independent from federal, state and local statutes and regulations so long as not inconsistent with federal law and regulation. 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 may be 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.

The Federal Energy Regulatory Commission (FERC) regulates interstate natural gas transportation and oversees natural gas marketing. FERC has issued a number of orders related to market transparency (e.g., price reporting indices, capacity release, standards of conduct, transportation capacity, general compliance) that extend FERC oversight to QEP. Since the enactment of the Energy Policy Act of 2005, granting FERC increased penalty authority for non compliance, FERC has targeted various issues in the natural gas industry for compliance audits and investigations. QEP owns three facilities that are directly regulated by FERC as either an interstate pipeline or a natural gas storage facility connected to interstate pipelines.

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

QEP may incur more taxes if certain federal income tax deductions currently available with respect to natural gas and oil exploration and development are eliminated as a result of future legislation. Our activities are subject to regulation by various federal, state and local tax laws and regulations and government agencies, including the Internal Revenue Service. The need to comply with new or revised tax laws or regulations, or new or changed interpretations or enforcement of existing tax laws or regulations, may have a material adverse effect on our business and results of operations. Federal budget proposals could potentially increase and accelerate the payment of federal income taxes for independent producers of natural gas and oil. The repeal of expensing of intangible drilling costs, percentage of depletion allowance and increased amortization periods for geological and geophysical expenses are some of the proposals that would have a significant impact on us. If enacted, these changes will increase the cost of exploration and development of natural gas and oil resources.

Federal or state hydraulic fracturing legislation could increase QEP’s costs and restrict its access to natural gas and oil reserves. All wells drilled in tight gas sand and shale reservoirs require hydraulic fracture stimulation to achieve economic production rates and recoverable reserves. A significant portion of the Company’s current and future production and reserve potential is derived from reservoirs that require hydraulic fracture stimulation to be commercially viable. Hydraulic fracture stimulation involves pumping fluid at high pressure into tight sand or shale reservoirs to artificially induce fractures. The artificially induced fractures allow better connection between the wellbore and the surrounding reservoir rock, thereby enhancing productive capacity and ultimate hydrocarbon recovery of each well. The fracture stimulation fluid is typically comprised of over 99 percent water and sand, with the remaining constituents consisting of additives designed to optimize the fracture stimulation treatment and production from the reservoir. The Company does not use diesel fuel in any of its fracturing

 

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operations. QEP obtains water for fracture stimulations from a variety of sources including industrial water wells and surface sources. When technically and economically feasible, the Company recycles flow-back and produced water, which reduces water consumption from surface and groundwater sources. The Company believes that the employment of fracture stimulation technology does not present any unique risks other than the inherent risks associated with natural gas and oil drilling and production operations described above. Currently, all well construction activities, including hydraulic fracture stimulation, are regulated by state agencies that review and approve all aspects of gas and oil well design and operation. New environmental initiatives, proposed federal and state legislation and rulemaking pertaining to hydraulic fracture stimulation could include additional permitting, and reporting and disclosure requirements and potential restrictions on the use of hydraulic fracture stimulation that could materially affect the Company’s ability to develop and produce gas and oil reserves.

The adoption of greenhouse gas emission or other environmental legislation could result in increased operating costs, delays in obtaining air pollution permits for new or modified facilities, and reduced demand for the natural gas, oil and NGL that QEP produces. 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. QEP’s ability to access and develop new natural gas reserves may be restricted by climate-change regulation. In recent legislative sessions bills have been 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. The Environmental Protection Agency (EPA) has adopted final regulations for the measurement and reporting of greenhouse gases emitted from certain large facilities (25,000 tons/year of carbon dioxide (CO2) equivalent) beginning with operations in 2010. The first report is to be filed with the EPA by March 31, 2011. In addition, several of the states in which QEP operates are considering various greenhouse gas registration and reduction programs. Carbon dioxide regulation could increase the price of natural gas, restrict access to or the use of natural gas, and/or reduce natural gas demand. Federal, state and local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for natural gas. While future climate-change regulation is possible, it is too early to predict how such regulation would affect QEP’s business, operations or financial results. It is uncertain whether QEP’s operations and properties, located in the Rocky Mountain and Midcontinent regions of the United States, are exposed to possible physical risks, such as severe weather patterns, due to climate change that may or may not be the result of man-made greenhouse gases. However, management does not believe such physical risks are reasonably likely to have a material effect on the company’s financial condition or results of operations.

Derivatives regulation could increase QEP’s liquidity risks by restricting its use of derivative instruments. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which was passed by Congress and signed into law in July 2010, contains significant derivatives regulation, including a requirement that certain derivative transactions be cleared on exchanges, a requirement to post cash collateral (commonly referred to as “margin”) for such derivative transactions, and strong business conduct standards. The Dodd-Frank Act provides for a potential exception from clearing and cash collateral requirements for commercial end-users. The availability of this “end-user exemption” depends on how the Commodities Futures and Trading Commission (CFTC) defines a number of terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. The CFTC is in the process of proposing definitions to determine which entities will face additional requirements for clearing, trading and posting of margin.

Depending on the rules and definitions adopted by the CFTC, the Dodd-Frank Act could require that QEP post significant amounts of cash collateral with its dealer counterparties for QEP’s derivative transactions. A sudden, unexpected margin call triggered by rising commodity prices would have an immediate negative impact on QEP’s liquidity, forcing QEP to divert capital from exploration, development and production activities. Requirements to post cash collateral could not only cause significant liquidity issues by reducing the Company’s flexibility in using its cash and other sources of funds, such as its revolving credit facility, but could also cause QEP to incur additional debt. In addition, a requirement for QEP’s counterparties to post cash collateral would likely result in additional costs being passed on to QEP, thereby decreasing the effectiveness of its commodity

 

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derivatives and its profitability. If the costs of complying with the clearing and margin requirements and business conduct rules under the Dodd-Frank Act significantly increase the costs of entering into commodity derivative transactions, QEP may reduce its commodity derivative program, which could increase its exposure to fluctuating commodity prices.

Other Risks

General economic and other conditions impact QEP’s results. QEP’s results may also be negatively affected by: changes in global economic conditions; changes in regulation; availability and economic viability of gas and oil properties for sale or exploration; creditworthiness of counterparties; rate of inflation and interest rates; assumptions used in business combinations; weather and natural disasters; changes in customers’ credit ratings; competition from other forms of energy, other pipelines and storage facilities; effects of accounting policies issued periodically by accounting standard-setting bodies; terrorist attacks or acts of war; changes in business or financial condition; changes in credit ratings; and availability of financing for QEP.

The underfunded status of our pension plans may require large contributions which may divert funds from other uses. Approximately one-quarter of our employees participate in defined benefit pension plans, although effective January 1, 1997, we closed participation in the QEP Retirement Plan. Over time, periods of declines in interest rates and pension asset values may result in a reduction in the funded status of our pension plans. As of December 31, 2010, our pension plans were $47.1 million underfunded. The underfunded status of our pension plans may require us to make large contributions to such plans. We made cash contributions of $1.6 million in 2010 to our defined benefit pension plans and expect to make contributions of approximately $11.9 million to such plans in 2011. However, we cannot predict whether changing economic conditions, the future performance of assets in the plans or other factors will require us to make contributions in excess of our current expectations, diverting funds we would otherwise apply to other uses.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

 

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ITEM 2. PROPERTIES

EXPLORATION AND PRODUCTION

Reserves – QEP Energy

QEP Energy’s reserve estimates are prepared by Ryder Scott Company, L.P., independent reservoir-engineering consultants. The estimates of proved reserves at December 31, 2010, were made in accordance with amended reserves definitions included in the SEC’s rules for the Modernization of Oil and Gas Reporting, that were adopted December 31, 2009. The most significant amendments affecting the Company include, allowing the use of reliable technologies to estimate and categorize reserves and using the arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period (unless contractual arrangements designate the price) to be used to calculate economic producibility of reserves and the discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to Proved Reserves. Refer to Note 16 of the consolidated financial statements included in Item 8 of Part II of this Annual Report for additional information regarding estimates of proved reserves and the preparation of such estimates.

At December 31, 2010, approximately 88% of QEP Energy’s estimated proved reserves were Company operated. Proved developed reserves represented 53% of the Company’s total proved reserves at December 31, 2010 while the remaining 47% of reserves were proved undeveloped. All reported reserves are located in the United States. QEP Energy does not have any long-term supply contracts with foreign governments, reserves of equity investees or reserves of subsidiaries with a significant minority interest. QEP Energy’s estimated reserves are summarized as follows:

 

     December 31, 2010  
     Natural
Gas
     Oil and
NGL
     Natural Gas
Equivalents(1)
 
     (Bcf)      (MMbbl)      (Bcfe)  

Proved developed reserves

     1,404.8         34.4         1,611.5   

Proved undeveloped reserves

     1,208.1         35.2         1,419.2   
                          

Total proved reserves

     2,612.9         69.6         3,030.7   
                          

 

(1)

Oil and NGLs are converted to natural gas at the ratio of one bbl of oil or NGL to six Mcf of natural gas.

QEP Energy’s reserve statistics for the years ended December 31, 2008 through 2010, are summarized below:

 

Year    Year End Reserves (Bcfe)    Natural Gas and Oil Production
(Bcfe)
  

Reserve Life Index(1)

(Years)

2008

   2,218.1    171.4    12.9

2009

   2,746.9    189.5    14.5

2010

   3,030.7    229.0    13.2

 

(1)

Reserve life index is calculated by dividing year-end proved reserves by production for such year.

QEP Energy’s proved reserves in major operating areas at December 31, 2010 and 2009 are summarized below:

 

     2010      2009  
     (Bcfe)      (% of total)      (Bcfe)      (% of total)  

Midcontinent

     1,170.5         39         1,100.5         40   

Pinedale Anticline

     1,348.9         44         1,300.7         47   

Uinta Basin

     212.8         7         197.7         7   

Rockies Legacy

     298.5         10         148.0         6   
                                   

Total QEP Energy

     3,030.7         100         2,746.9         100   
                                   

Estimates of proved gas and oil reserves have been completed in accordance with professional engineering standards and the Company’s established internal controls, which includes the compliance oversight of a multi-

 

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functional reserves review committee responsible to the Company’s board of directors. QEP Energy’s estimated proved reserves have been prepared by Ryder Scott Company, L.P., independent reservoir engineering consultants, in accordance with the SEC’s Regulation S-X and ASC 932 as amended. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation. Refer to Note 16 of the consolidated financial statements included in Item 8 of Part II of this Annual Report for additional information pertaining to QEP Energy’s proved reserves as of the end of each of the last three years.

In addition to this filing, QEP Energy will file reserves estimates as of December 31, 2010, with the Energy Information Administration of the Department of Energy on Form EIA-23. Although 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 net realized prices per Mcf of natural gas, per bbl of oil and NGL produced, and the operating expenses per Mcfe for the years ended December 31, 2010, 2009 and 2008.

 

     Year Ended December 31,  
     2010      2009      2008  

QEP Energy

        

Volumes produced and sold

        

Natural gas (Bcf)

     203.8         168.7         151.9   

Oil and NGL (MMbbl)

     4.2         3.5         3.3   

Total production (Bcfe)

     229.0         189.5         171.4   

Average net realized price, net to the well(1)

        

Natural gas (per Bcf)

   $ 4.74       $ 6.39       $ 7.56   

Oil and NGL (per bbl)

     56.80         45.91         72.96   

Lifting costs (per Mcfe)

        

Lease operating expense

   $ 0.56       $ 0.67       $ 0.73   

Production taxes

     0.34         0.31         0.61   
                          

Total lifting costs

   $ 0.90       $ 0.98       $ 1.34   
                          

 

(1)

Includes the impact of all settled commodity price derivatives

Productive Wells

The following table summarizes the Company’s productive wells as of December 31, 2010. All wells are located in the United States.

 

     Gas      Oil      Total  

Gross

     4,844         2,121         6,965   

Net

     2,224         436         2,660   

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 2010, the Company had 94 gross wells with multiple completions.

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

 

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Leasehold Acreage

The following table summarizes developed and undeveloped-leasehold acreage in which the Company owns a working interest or mineral interest as of December 31, 2010. “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 United States.

 

     Developed Acres(1)      Undeveloped Acres(2)      Total Acres  
     Gross      Net      Gross      Net      Gross      Net  

Arkansas

     32,642         9,260         5,498         3,594         38,140         12,854   

Colorado

     155,000         105,625         158,025         53,839         313,025         159,464   

Kansas

     29,822         12,922         52,459         17,245         82,281         30,167   

Louisiana

     55,812         45,215         24,106         22,975         79,918         68,190   

Montana

     15,094         7,706         307,134         53,027         322,228         60,733   

New Mexico

     96,969         70,756         32,939         12,618         129,908         83,374   

North Dakota

     12,068         3,681         237,877         96,121         249,945         99,802   

Oklahoma

     1,596,688         293,403         261,769         148,474         1,858,457         441,877   

South Dakota

     —           —           204,398         107,151         204,398         107,151   

Texas

     133,409         46,424         56,416         50,959         189,825         97,383   

Utah

     162,820         130,788         273,359         184,458         436,179         315,246   

Wyoming

     289,270         181,211         383,248         276,154         672,518         457,365   

Other

     2,429         735         158,475         43,350         160,904         44,085   
                                                     

Total

     2,582,023         907,726         2,155,703         1,069,965         4,737,726         1,977,691   
                                                     

 

(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 established from the acreage subject to the lease prior to that date. Leases held by production remain in effect until production ceases. The following table sets forth the gross and net acres subject to leases summarized in the preceding table that will expire during the periods indicated:

Leaseholds Expiring

 

     Undeveloped Acres Expiring  
           Gross                  Net        

12 months ending December 31,

  

2011

     125,647         80,786   

2012

     68,154         45,760   

2013

     140,959         77,445   

2014

     57,707         46,779   

2015 and later

     241,770         220,340   

 

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Drilling Activity

The following table summarizes the number of development and exploratory wells drilled on acreage owned by QEP during the years indicated.

 

     Year Ended December 31,  
     Productive      Dry  
     2010      2009      2008      2010      2009      2008  

Net Wells Completed

                 

Exploratory

     16.2         3.7         2.3         1.9                 0.9   

Development

     170.5         154.5         219.2                         6.3   

Gross Wells Completed

                 

Exploratory

     33         12         10         2                 2   

Development

     516         273         456                 1         13   

MIDSTREAM FIELD SERVICES – QEP Field Services

QEP Field Services owns 1,855 miles of gathering lines in Utah, Wyoming, Colorado and Louisiana. At December 31, 2010 QEP Field Services also owns processing plants, which remove NGL from the natural gas stream, that have an aggregate processing capacity, of 800 MMcf per day of unprocessed natural gas. In addition, QEP Field Services owns treating facilities in northwest Louisiana, which remove CO2 from the natural gas stream, that have an aggregate treating capacity of 530 MMcf per day of untreated natural gas. QEP Field Services also owns compression facilities and field dehydration and measurement systems. The 21-mile, 20-inch diameter pipeline owned by Rendezvous Pipeline can deliver up to 300 MMcf of natural gas per day to the Kern River Pipeline. QEP Field Services partnership facilities include the RGS system, consisting of 330 miles of gathering lines and associated field equipment, the UBFS system, which consists of 76 miles of gathering lines and associated field equipment and the Three Rivers system, which consists of 57 miles of gathering lines and associated field equipment.

In January 2011, QEP Field Services put into service the 150 MMcf per day cryogenic Iron Horse processing plant expansion of its Stagecoach processing complex in the Uinta Basin of eastern Utah. Also, during the fourth quarter of 2011, QEP Field Services expects to commission its 420 MMcf per day cryogenic processing plant expansion of its Blacks Fork processing complex located in the Green River Basin of southwestern Wyoming.

ENERGY MARKETING – QEP Marketing

QEP Marketing, through its wholly owned subsidiary Clear Creek Storage Company, LLC, owns and operates an underground gas-storage reservoir in southwestern Wyoming. The reservoir has a gas storage capacity of 8 Bcf, comprised of an inventory of approximately 4 Bcf of QEP Marketing-owned cushion gas and working gas storage of 4 Bcf.

 

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ITEM 3. LEGAL PROCEEDINGS

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

Environmental Claims

United States of America v. QEP Field Services, Civil No. 208CV167, U.S. District Court for Utah. The U.S. Environmental Protection Agency (EPA) alleges that QEP Field Services (f/k/a Questar Gas Management) violated the Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for these facilities renders them “major sources” of emissions for criteria and hazardous air pollutants even though controls were installed. Categorization of the facilities as “major sources” affects the particular regulatory program and requirements applicable to those facilities. EPA claims that QEP Field Services failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations for testing and reporting, among other requirements. QEP Field Services contends that its facilities have pollution controls installed that reduce their actual air emissions below major source thresholds, rendering them subject to different regulatory requirements applicable to non-major sources. QEP Field Services has vigorously defended EPA’s claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying Utah’s CAA program or EPA’s prior permitting practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict all reasonably possible outcomes; however, management believes the Company has accrued a reasonable loss contingency that is an immaterial amount, for the anticipated most likely outcome. The Ute Indian Tribe and individual members of its Business Committee have now intervened as co-plaintiffs asserting the same CAA claims as the federal government.

QEP Energy v. U.S. Environmental Protection Agency, No. 09-9538, U.S. Court of Appeals for the 10th Circuit. On July 10, 2009 QEP Energy filed a petition with the U.S. 10th Circuit Court of Appeals challenging an administrative compliance order dated May 12, 2009 (Order), issued by EPA which asserts that QEP Energy’s Flat Rock 14P well in the Uinta Basin and associated equipment is a major source of hazardous air pollutants and its operation fails to comply with certain regulations of the CAA. The Order required immediate compliance. QEP Energy denies that the drilling and operation of the 14P well and associated equipment violates any provisions of the CAA and intends to vigorously defend this claim.

ITEM 4. REMOVED AND RESERVED

 

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PART II

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

QEP’s common stock is listed and traded on the New York Stock Exchange (NYSE:QEP). As of February 18, 2011, QEP had 8,322 shareholders of record. The declaration and payment of dividends are at the discretion of QEP’s Board of Directors and the amount thereof will depend on QEP’s results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other factors deemed relevant by the Board of Directors. Following is a summary of the high and low sales price per share of QEP’s common stock on the NYSE and quarterly dividends paid per share:

 

     High price      Low price      Dividend  
            (per share)         

2010

        

First quarter(1)

   $ —         $ —         $ —     

Second quarter(1)

     —           —           —     

Third quarter

     35.15         27.90         0.02   

Fourth quarter

   $ 38.33       $ 29.54         0.02   
              
         $ 0.04   
              

 

(1)

Public trading of the common shares of the Company commenced on July 1, 2010.

Stockholder Return Performance Presentation

The performance presentation shown below is being furnished as required by applicable rules of the SEC and was prepared using the following assumptions:

 

   

A $100 investment was made in QEP common, the S&P 500 Index and our peer group as of July 1, 2010, which is the date when our common stock began trading on the New York Stock Exchange;

 

   

Investment in our peer group was weighted based on the stock market capitalization of each individual company within the peer group at the beginning of the period; and

 

   

Dividends were reinvested on the relevant payment dates.

 

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Our peer group, as defined, consists of the following companies: Cabot Oil & Gas Corporation, Cimarex Energy Company, Denbury Resources Inc., EOG Resources, Inc., Forest Oil Corporation, Newfield Exploration Company, Noble Energy, Inc., Petrohawk Energy Corporation, Pioneer Natural Resources Company, Plains Exploration & Production Company, Quicksilver Resources, Inc., Range Resources Corporation, Southwestern Energy Company, Ultra Petroleum Corporation and Whiting Petroleum Corporation. Management believes this peer group provides a meaningful comparison based upon our review of asset size, geographic location of assets, market capitalization, revenues, culture and performance, among other things.

LOGO

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

QEP had no unregistered sales of equity during the fourth quarter of 2010. QEP repurchased shares in conjunction with tax-payment elections under the Company’s Long-term Stock Incentive Plan and rollover shares used in exercising stock options.

The following table sets forth the Company’s purchases of common stock registered under Section 12 of the Exchange Act that occurred during the quarter ended December 31, 2010.

 

2010

   Number of Shares
Purchased
     Average Price per
Share
     Total Number of Shares
Purchased as Part of
Publicly Announced
Plans
     Maximum Number of
Shares that May Yet Be
Purchased Under the
Plans
 

October

     13,450       $ 31.39         —           —     

November

     30,722         34.43         —           —     

December

     44,924         36.65         —           —     
                 

Total

     89,096       $ 35.09         
                 

 

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ITEM 6. SELECTED FINANCIAL DATA

Selected financial data for the five years ended December 31, 2010, is provided in the table below. Refer to Item 7 and Item 8 in Part II of this annual report for discussion of facts affecting the comparability.

 

     Year Ended December 31,  
     2010     2009     2008     2007     2006  
     (in millions, except per-share amounts)  

Results Of Operations(1)

          

Revenues

   $ 2,246.4      $ 1,972.5      $ 2,318.8      $ 1,688.1      $ 1,685.7   

Operating income

     545.3        585.5        933.2        584.1        511.7   

Income from continuing operations

     285.9        215.4        520.6        361.6        306.1   

Discontinued operations net of income tax

     43.2        80.7        73.9        59.2        50.0   

Net income attributable to QEP

     326.2        293.5        585.5        420.8        356.1   

Earnings per common share attributable to QEP

          

Basic from continuing operations

   $ 1.61      $ 1.23      $ 2.96      $ 2.11      $ 1.79   

Basic from discontinued operations

     0.25        0.46        0.43        0.34        0.29   
                                        

Basic total

   $ 1.86      $ 1.69      $ 3.39      $ 2.45      $ 2.08   
                                        

Diluted from continuing operations

   $ 1.60      $ 1.21      $ 2.90      $ 2.05        1.74   

Diluted from discontinued operations

     0.24        0.46        0.42        0.34        0.29   
                                        

Diluted total

   $ 1.84      $ 1.67      $ 3.32      $ 2.39      $ 2.03   
                                        

Weighted-average common shares outstanding

          

Used in basic calculation

     175.3        174.1        172.8        172.0        170.9   

Used in diluted calculation

     177.3        176.3        176.1        175.9        175.2   

Financial Position

          

Total Assets at December 31,

   $ 6,785.3      $ 6,481.4      $ 6,342.7      $ 3,821.6      $ 3,261.8  

Capitalization at December 31,

          

Long-term debt

     1,530.8        1,348.7        1,299.1        499.3        399.2   

Total equity

     3,063.1        2,808.7        2,779.4        1,860.1        1,544.8   
                                        

Total Capitalization

   $ 4,593.9      $ 4,157.4      $ 4,078.5      $ 2,359.4      $ 1,944.0   
                                        

Cash Flow From Continuing Operations

          

Net cash provided by operating activities

   $ 997.5      $ 1,149.4      $ 1,224.7      $ 807.0      $ 654.8   

Capital expenditures

     (1,469.0     (1,198.4     (2,136.7     (838.9     (670.0

Net cash used in investing activities

     (1,390.5     (1,146.4     (2,021.0     (867.9     (621.9

Net cash provided by (used in) financing activities

     373.7        (8.8     818.7        44.1        (17.2

Non-GAAP Measures

          

Adjusted EBITDA(2)

   $ 1,140.5      $ 1,165.5      $ 1,310.7      $ 890.7      $ 737.7   

 

(1)

QEP completed a Spin-off from Questar in June 2010 as discussed in more detail in the Explanatory Note in Part I, Item 1 of this Annual Report on Form 10-K. As a result of the Spin-off, Wexpro’s financial results have been reflected as discontinued operations and all prior periods have been recast.

(2)

Adjusted EBITDA is a non-GAAP measure. Management defines Adjusted EBITDA as net income before the following items: discontinued operations, unrealized gain and losses on basis-only swaps, gains and losses from assets sales, interest and other income, income taxes interest expense, separations costs, loss on early extinguishment of debt, depreciation, depletion and amortization, abandonment and impairment, and exploration expense. Management believes Adjusted EBITDA is an important measure of the Company’s cash flow and liquidity and an important measure for comparing the Company’s financial performance to other gas and oil producing companies.

 

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The following table reconciles QEP Resources’ net income to Adjusted EBITDA:

 

     Year Ended December 31,  
     2010     2009     2008     2007     2006  
     (in millions)  

Adjusted EBITDA

          

Net income attributable to QEP

   $ 326.2      $ 293.5      $ 585.5      $ 420.8      $ 356.1   

Net income attributable to noncontrolling interest

     2.9        2.6        9.0        —          —     
                                        

Net income

     329.1        296.1        594.5        420.8        356.1   

Discontinued operations, net of tax

     (43.2     (80.7     (73.9     (59.2     (50.0
                                        

Income from continuing operations

     285.9        215.4        520.6        361.6        306.1   

Unrealized gain / (loss) basis-only swaps

     (121.7     164.0        79.2        (5.7     1.9   

Net (gain) loss from asset sales

     (12.1     (1.5     (60.4     0.6        (25.3

Interest and other income

     (2.3     (4.5     (10.2     (7.8     (4.5

Income taxes

     167.0        117.6        283.6        211.3        180.6   

Interest expense

     84.4        70.1        61.7        33.6        33.4   

Separation costs

     13.5        —          —          —          —     

Loss from early extinguishment of debt

     13.3        —          —          —          1.7   

Depreciation, depletion and amortization

     643.4        559.1        361.5        263.9        201.9   

Abandonment and impairment

     46.1        20.3        45.4        11.2        7.5   

Exploration

     23.0        25.0        29.3        22.0        34.4   
                                        

Adjusted EBITDA

   $ 1,140.5      $ 1,165.5      $ 1,310.7      $ 890.7      $ 737.7   
                                        

 

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Table of Contents

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the results. MD&A should be read in conjunction with the Consolidated Financial Statements and related notes included in Item 8 of this Annual Report on Form 10-K.

The following information updates the discussion of QEP’s financial condition provided in its 2009 Form 10-K filing, and analyzes the changes in the results of operations between the years ended December 31, 2010 versus December 31, 2009 and December 31, 2009 versus December 31, 2008.

OVERVIEW

QEP Resources, Inc. (QEP or the Company), is an independent natural gas and oil exploration and production company. QEP is a holding company with three major lines of business – gas and oil exploration and production, midstream field services, and energy marketing – which are conducted through three principal subsidiaries:

 

   

QEP Energy Company (QEP Energy) acquires, explores for, develops and produces natural gas, oil, and natural gas liquids (NGL);

 

   

QEP Field Services Company (QEP Field Services) provides midstream field services including natural gas gathering, processing and treating services for affiliates and third parties; and

 

   

QEP Marketing Company (QEP Marketing) markets equity and third-party natural gas and oil, provides risk-management services, and owns and operates an underground gas-storage reservoir.

Highlights

QEP’s net income increased 11% in 2010 compared with 2009 due to unrealized mark-to-market gains on basis-only swaps, higher production, higher net realized crude oil and NGL prices and higher gathering and processing margins at QEP Field Services, partially offset by lower net realized natural gas prices. QEP reported record production of 229.0 Bcfe in 2010 and all divisions, other than the Uinta Basin, recorded production that was greater than in 2009. Year-end proved reserves increased by 10% over the prior year to 3.03 Tcfe.

On June 30, 2010, all of the shares of common stock of QEP were distributed through a tax-free, pro rata dividend to Questar shareholders. Each Questar shareholder received one share of QEP common stock for each share of Questar common stock held (including fractional shares). In conjunction with the Spin-off, QEP distributed the common stock of its wholly-owned subsidiary, Wexpro, to Questar. In addition, Questar contributed $250.0 million of equity to QEP prior to the Spin-off.

In the third quarter of 2010, QEP completed the refinancing of senior notes that were tendered to the Company as a result of the Spin-off. In total, QEP purchased $638.0 million principal amount of senior notes using proceeds from its term loan and revolving credit facilities. In August, QEP issued $625.0 million principal amount of senior notes due 2021 to refinance a portion of the indebtedness under its revolving credit facility and all the outstanding indebtedness under the term loan and terminated all of the commitments under the term loan. At December 31, 2010, QEP had five issues of senior notes totaling $1,137.0 million principal amount outstanding compared to $1,150.0 million principal amount outstanding at June 30, 2010.

 

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Strategies

We create value for our shareholders through returns-focused growth, superior execution, and a low cost structure. To achieve these objectives we will strive to:

 

   

Attract and retain the best people

 

   

Allocate capital to the projects that generate the best returns

 

   

Maintain a sustainable inventory of low-cost, high margin resource plays

 

   

Be in the best parts of the best plays

 

   

Build contiguous acreage positions to drive efficiencies

 

   

Be the operator of our assets whenever possible

 

   

Be the low-cost driller and producer in each area where we operate

 

   

Own and operate midstream infrastructure in our core producing areas to control our future and capture value downstream of the wellhead

 

   

Build gas processing plants to extract liquids from our gas streams

 

   

Gather, compress and treat our production to drive down costs

 

   

Actively market our equity production to maximize value

 

   

Utilize commodities derivatives to hedge against a decline in the realized prices of our natural gas and oil production and lock in acceptable cash flows to support future capital expenditures

 

   

Operate in a safe and environmentally responsible manner

 

   

Maintain a strong balance sheet and financial flexibility that allows us to take advantage of both organic growth and acquisition opportunities

RESULTS OF OPERATIONS

Following are comparisons of net income from continuing operations attributable to QEP by line of business:

 

     Year Ended December 31,      Change  
     2010     2009      2008      2010 vs. 2009     2009 vs. 2008  
     (in millions, except per-share amounts)  

QEP Energy

   $ 203.9      $ 134.9      $ 408.0      $ 69.0      $ (273.1

QEP Field Services

     91.1        69.4        81.5        21.7        (12.1

QEP Marketing and other

     6.7        8.5        22.1        (1.8     (13.6

Certain costs of separation and early extinguishment of debt

     (18.7     —           —           (18.7     —     
                                          

Net income from continuing operations attributable to QEP

   $ 283.0      $ 212.8      $ 511.6      $ 70.2      $ (298.8
                                          

Earnings per diluted share from continuing operations

   $ 1.60      $ 1.21       $ 2.90       $ 0.39      $ (1.69

Average diluted shares

     177.3        176.3         176.1         1.0        0.2   

 

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QEP ENERGY

QEP Energy reported net income of $203.9 million in 2010, an increase of 51% from $134.9 million in 2009, but lower than 2008 net income of $408.0 million when natural gas prices were significantly higher. Unrealized mark-to-market gains on natural gas basis-only swaps, higher production of 229.0 Bcfe and higher net realized crude oil and NGL prices were the main drivers for this increase. These factors were partially offset by lower net realized natural gas prices. Unrealized mark-to-market gains and losses on natural gas basis-only swaps increased pre-tax income $121.7 million in 2010 compared to a net pre-tax loss of $164.0 million for these items in 2009. Net gains from sales of assets increased pre-tax income by $13.7 million in 2010 compared to a net pre-tax gain of $1.6 million in 2009. Following is a summary of QEP Energy financial and operating results:

 

     Year Ended December 31,     Change  
     2010     2009     2008     2010 vs. 2009     2009 vs. 2008  
     (in millions)  

QEP Energy Operating Income

          

REVENUES

          

Natural gas sales

   $ 1,086.9      $ 1,103.9      $ 1,147.7      $ (17.0   $ (43.8

Oil and NGL sales

     238.9        158.5        237.5        80.4        (79.0

Other

     5.0        4.9        6.9        0.1        (2.0
                                        

Total Revenues

     1,330.8        1,267.3        1,392.1        63.5        (124.8

OPERATING EXPENSES

          

Lease operating expenses

     127.3        127.5        125.4        (0.2     2.1   

General and administrative

     78.0        68.0        55.8        10.0        12.2   

Production and property taxes

     77.8        58.3        104.0        19.5        (45.7

Depreciation, depletion and amortization

     592.5        512.8        330.9        79.7        181.9   

Exploration expenses

     23.0        25.0        29.3        (2.0     (4.3

Abandonment and impairment

     46.1        20.3        44.6        25.8        (24.3

Natural gas purchases

     —          —          0.5        —          (0.5
                                        

Total Operating Expenses

     944.7        811.9        690.5        132.8        121.4   

Net gain (loss) from asset sales

     13.7        1.6        60.4        12.1        (58.8
                                        

Operating Income

     399.8        457.0        762.0        (57.2     (305.0
                                        

Interest and other income

     2.1        3.9        7.5        (1.8     (3.6

Income from unconsolidated affiliates

     0.2        0.1        0.5        0.1        (0.4

Unrealized and realized gain (loss) on basis-only swaps

     —          (189.6     (79.2     189.6        (110.4

Interest Expense

     (78.5     (63.9     (58.3     (14.6     (5.6
                                        

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

     323.6        207.5        632.5        116.1        (425.0

Income Taxes

     (119.7     (72.6     (224.5     (47.1     151.9   
                                        

NET INCOME ATTRIBUTABLE TO QEP Energy

   $ 203.9      $ 134.9      $ 408.0      $ 69.0      $ (273.1
                                        

 

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Production

QEP Energy production totaled 229.0 Bcfe in 2010 compared to 189.5 Bcfe in 2009 and 171.4 Bcfe in 2008. On an energy-equivalent basis, natural gas comprised approximately 89% of 2010 production. A summary of natural gas-equivalent production by major operating area is shown in the following table:

 

     Year Ended December 31,      Change  
     2010      2009      2008      2010 vs. 2009     2009 vs. 2008  

QEP Energy production by operating area

     (in Bcfe)   

Midcontinent

     120.4         87.8         67.8         32.6        20.0   

Pinedale Anticline

     68.5         61.8         56.8         6.7        5.0   

Uinta Basin

     21.4         23.2         26.9         (1.8     (3.7

Rockies Legacy

     18.7         16.7         19.9         2.0        (3.2
                                           

Total production

     229.0         189.5         171.4         39.5        18.1   
                                           

QEP Energy production volumes

             

Natural gas (Bcf)

     203.8         168.7         151.9         35.1        16.8   

Oil and NGL (MMbbl)

     4.2         3.5         3.3         0.7        0.2   
                                           

Total production (Bcfe)

     229.0         189.5         171.4         39.5        18.1   
                                           

Average daily production (MMcfe)

     627.4         519.1         468.3         108.3        50.8   

Net production in the Midcontinent grew 37% to 120.4 Bcfe in 2010 compared to 87.8 Bcfe in 2009. Midcontinent production growth was driven by the ongoing development drilling in the Haynesville Shale play in Elm Grove, Thorn Lake and Woodardville fields in northwest Louisiana, continued development of the Granite Wash/Atoka play in the Texas Panhandle, and the Woodford “Cana” Shale horizontal gas play in the Anadarko Basin of western Oklahoma.

Net production from the Pinedale Anticline in western Wyoming grew 11% to 68.5 Bcfe in 2010 as a result of ongoing development drilling. Historically, seasonal access restrictions imposed by the Bureau of Land Management have limited the ability to drill and complete wells at Pinedale during the mid-November to early May period. In September 2008, the BLM issued a Record of Decision (ROD) on the Final Supplemental Environmental Impact Statement for long-term development of natural gas resources in the Pinedale Anticline Project Area (PAPA). Under the ROD, QEP Energy is allowed to drill and complete wells year-round in one of the five Concentrated Development Areas defined in the PAPA. The ROD contains additional requirements and restrictions on development of the PAPA.

In the Uinta Basin, net production decreased 8% to 21.4 Bcfe in 2010. Production volumes were adversely impacted by decreased drilling activity in response to low natural gas prices.

Rockies Legacy net production in 2010 increased 12% to 18.7 Bcfe, 2.0 Bcfe higher than the year-ago period due to increased drilling activity in the Bakken play in North Dakota. QEP Energy Rockies Legacy properties include all Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin.

 

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Pricing

Realized prices for natural gas at QEP Energy were lower in 2010 than in 2009 and 2008, while 2010 realized oil and NGL prices were higher than in 2009 but lower than in 2008. A regional comparison of QEP Energy’s average realized prices, including the impact of hedges, are shown in the following table:

 

     Year Ended December 31,      Change  
     2010      2009      2008      2010 vs. 2009     2009 vs. 2008  

Natural gas (per Mcf)

             

Midcontinent

   $ 5.85       $ 7.01       $ 8.63       $ (1.16   $ (1.62

Rocky Mountains

     4.73         6.12         6.85         (1.39     (0.73

Volume-weighted average

     5.33         6.54         7.56         (1.21     (1.02

Oil and NGL (per bbl)

             

Midcontinent

   $ 50.63       $ 46.05       $ 72.82       $ 4.58      $ (26.77

Rocky Mountains

     61.09         45.82         73.05         15.27        (27.23

Volume-weighted average

     56.80         45.91         72.96         10.89        (27.05

A comparison of net realized average natural gas prices, including realized losses on basis-only swaps which did not qualify for hedge accounting and are therefore not included in revenue, are shown in the following table.

 

     Year Ended December 31,     Change  
     2010     2009     2008     2010 vs. 2009     2009 vs. 2008  

Average field-level natural gas price ($ per Mcf)

   $ 3.60      $ 2.99      $ 6.73      $ 0.61      $ (3.74

Natural gas hedging impact ($ per Mcf)

     1.73        3.55        0.83        (1.82     2.72   
                                        

Average revenue ($ per Mcf)(1)

     5.33        6.54        7.56        (1.21     (1.02

Realized losses on basis-only swaps ($ per Mcf)(2)

     (0.59     (0.15     —          (0.44     (0.15
                                        

Net realized natural gas price ($ per Mcf)

   $ 4.74      $ 6.39      $ 7.56      $ (1.65   $ (1.17
                                        

Average field-level oil and NGL price ($ per bbl)

   $ 58.87      $ 45.45      $ 82.74      $ 13.42      $ (37.29

Oil and NGL hedging impact ($ per bbl)

     (2.07     0.46        (9.78     (2.53     10.24   
                                        

Net realized oil and NGL price ($ per bbl)(1)

   $ 56.80      $ 45.91      $ 72.96      $ 10.89      $ (27.05
                                        

 

(1)

Reported in revenues in the consolidated income statement.

(2)

Reported below operating income in the consolidated income statement.

Realized losses on basis-only swaps of $121.7 million in 2010 and $25.6 million in 2009 are reported after operating income in the Consolidated Statements of Income.

 

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Commodity Derivatives Impact

The impact of QEP’s commodity derivative transactions on the Company’s financial statements is presented below. The net effect of the portion of natural gas basis-only swaps that do not qualify for hedge accounting is reported in the Consolidated Statements of Income below operating income. Derivative positions as of December 31, 2010, are summarized in Note 8 to the consolidated financial statements in Item 8 of this Annual Report on Form 10-K.

 

Volumes subject to commodity derivatives as a percent
of gas production
   Year Ended December 31,              
   2010     2009     2008              

Fixed-price swaps

     74     77 %     82 %    

Collars

     3     —          —         

Basis-only swaps

       15 %     3 %    

Volumes subject to commodity derivatives as a percent of oil production

          

Fixed-price swaps

     31     42 %     50 %    

Collars

     24     —          —         
Impact of hedges on financial statements (millions)                      Change  
                     2010 vs. 2009     2009 vs. 2008  

Natural gas sales

   $ 353.8      $ 599.3     $ 125.8     $ (245.5   $ 473.5   

Oil and NGL sales

     (8.7     1.6       (31.9 )     (10.3     33.5   

Impact of commodity derivatives that do not qualify for hedge accounting (millions)

          

Unrealized gain (loss) on basis-only swaps

   $ 121.7      $ (164.0 )   $ (79.2 )   $ 285.7      $ (84.8

Realized (loss) on basis-only swaps

     (121.7     (25.6 )     —          (96.1     (25.6

The change in unrealized gains and losses on natural gas basis-only swaps increased 2010 net income $76.3 million compared to a loss of $103.3 million in the year-earlier period. As of December 31, 2009, all of the Company’s basis-only swaps had been paired with NYMEX gas fixed-price swaps or price-collars and re-designated as cash flow hedges. Changes in the fair value of these derivative instruments subsequent to their re-designation were recorded in Accumulated Other Comprehensive Income (AOCI), however, changes in the fair value of these derivative instruments occurring prior to their re-designation were recorded in the Consolidated Statement of Income.

Operating Expenses

In 2010, QEP Energy operating expenses (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 decreased 5% to $4.17 per Mcfe versus $4.39 per Mcfe in 2009. Operating expenses are summarized in the following table:

 

     Year Ended December 31,      Change  
     2010      2009      2008      2010 vs. 2009     2009 vs. 2008  
     (per Mcfe)   

Depreciation, depletion and amortization

   $ 2.59       $ 2.71       $ 1.93       $ (0.12   $ 0.78   

Lease operating expenses

     0.56         0.67         0.73         (0.11     (0.06

General and administrative expense

     0.34         0.36         0.33         (0.02     0.03   

Allocated-interest expense

     0.34         0.34         0.34         —          —     

Production taxes

     0.34         0.31         0.61         0.03        (0.30
                                           

Total Operating expenses

   $ 4.17       $ 4.39       $ 3.94       $ (0.22   $ 0.45   
                                           

 

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In 2010, production volume-weighted per-unit depreciation, depletion and amortization (DD&A) expense decreased compared to 2009 primarily as a result of increased proved reserves related to higher field-level natural gas and oil prices compared to a year ago. Lease operating expenses per Mcfe were lower primarily due to higher production volumes combined with flat operating expenses. General and administrative expenses per Mcfe were slightly lower as a result of increased production volumes partially offset by higher expenses. The increase in general and administrative expenses was primarily related to higher labor, benefits and stock based compensation expenses. Allocated interest expense per Mcfe of production was unchanged. Production taxes per Mcfe increased slightly in 2010 as the result of higher field-level natural gas and oil sales prices. In most states, the Company pays production taxes based on a percentage of field level sales prices.

Exploration expense decreased $2.0 million or 8% in 2010 compared to 2009, despite an $8.7 million charge associated with an unsuccessful exploratory well drilled on the Borie Niobrara prospect in southeastern Wyoming. The overall decrease was due to lower geological, geophysical and other exploratory expenses in 2010 compared with 2009. Abandonment and impairment expense increased $25.8 million or 127% in 2010 compared to 2009. The increase is primarily due to higher impairment costs associated with our unproven acreage, which we amortize on a straight-line basis over the primary term of the lease. A significant amount of costs associated with such leases were added in 2009. Additionally, a $7.6 million impairment of an acreage block associated with the Borie Niobrara exploratory well discussed above contributed to this increase.

Other Items

QEP Energy completed the sale of properties located in Arkansas, Mississippi and other non-core locations and recognized a pre-tax gain of $13.7 million during the third quarter of 2010.

Major Operating Areas

Midcontinent

QEP Energy’s Midcontinent properties are distributed over a large area, including the Anadarko Basin of Oklahoma and the Texas Panhandle, the Arkoma Basin of Oklahoma and western Arkansas, and the Ark-La-Tex region of Arkansas, Louisiana and Texas. Excluding northwest Louisiana, the Granite Wash/Atoka Wash play in the Texas Panhandle and the Woodford Shale “Cana” play in western Oklahoma, QEP Energy Midcontinent leasehold interests are fragmented, with no significant concentration of property interests. In aggregate, Midcontinent properties contributed 120.4 Bcfe or 53% of 2010 production and comprised 1,170.5 Bcfe or 39% of QEP Energy total proved reserves at December 31, 2010.

QEP Energy has approximately 49,600 net acres of Haynesville Shale lease rights in northwest Louisiana. The true vertical depth to the top of the Haynesville Shale ranges from approximately 10,500 feet to 12,500 feet across QEP Energy’s leasehold. The Haynesville Shale underlies the Hosston and Cotton Valley formations that QEP Energy has been developing in northwest Louisiana for over a decade. QEP Energy continues drilling in the Haynesville Shale and intends to drill or participate in up to 80 gross (operated and non-operated) horizontal Haynesville Shale wells in 2011 compared to 86 gross wells in 2010. As of December 31, 2010, QEP Energy had six operated rigs drilling in the project area and had working interests in 121 gross Haynesville Formation wells and a total of 716 gross producing wells in northwest Louisiana compared to 31 gross Haynesville Formation wells and a total of 610 gross producing wells at December 31, 2009.

QEP Energy has approximately 68,000 net acres of Woodford Shale lease rights in western Oklahoma. The true vertical depth to the top of the Woodford Shale ranges from approximately 10,500 feet to 14,500 feet across QEP Energy’s leasehold. QEP Energy intends to drill or participate in up to 64 gross horizontal Woodford Shale wells in 2011 compared to 54 gross wells in 2010. As of December 31, 2010, QEP Energy had two operated rigs drilling in the project area and had working interests in 102 gross producing Woodford Shale wells in western Oklahoma compared to 49 gross wells at December 31, 2009.

 

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QEP Energy has approximately 41,000 net acres of Granite Wash/Atoka Wash lease rights in the Texas Panhandle and western Oklahoma and has been drilling vertical Granite Wash/Atoka Wash wells for over a decade. In the past year, QEP and other operators have drilled a number of successful horizontal wells in the Granite Wash/Atoka Wash play. The true vertical depth to the top of the Granite Wash/Atoka Wash interval ranges from approximately 11,100 feet to 15,900 feet across QEP Energy’s leasehold. As of December 31, 2010, QEP Energy had three rigs drilling horizontal Granite Wash/Atoka Wash wells in the Texas Panhandle and had working interests in 48 gross producing horizontal Granite Wash/Atoka Wash wells in the Texas Panhandle and western Oklahoma compared to 15 gross wells at December 31, 2009. QEP Energy intends to drill or participate in up to 35 gross horizontal Granite Wash/Atoka Wash wells in 2011 compared to 33 gross wells in 2010.

Pinedale Anticline

As of December 31, 2010, QEP Energy had working interests in 529 gross producing wells on the Pinedale Anticline compared to 426 gross wells at December 31, 2009. Of the 529 gross producing wells, QEP Energy has working interests in 508 wells and overriding royalty interests in an additional 21 wells. The Pinedale Anticline contributed 68.5 Bcfe or 30% of QEP Energy 2010 production and comprised 1,348.9 Bcfe or 44% of QEP Energy total proved reserves at December 31, 2010.

In 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10-acre-density drilling for Lance Pool wells on about 12,700 acres of QEP Energy’s 17,872-acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the currently estimated productive limits of QEP Energy 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 QEP Energy’s Pinedale leasehold. The true vertical depth to the top of the Lance Pool tight gas sand reservoir interval ranges from 8,500 to 9,500 feet across QEP Energy’s acreage. If five-acre-density development is appropriate for a majority of its leasehold, the Company currently estimates that up to 1,300 additional wells will be required to fully develop the Lance Pool on its acreage.

Uinta Basin

As of December 31, 2010, QEP Energy had a working interest in 2,098 gross producing wells in the Uinta Basin of eastern Utah, compared to 2,334 gross wells at December 31, 2009. At December 31, 2010, properties in the Uinta Basin contributed 21.4 Bcfe or 9% of 2010 production and comprised 212.8 Bcfe or 7% of QEP Energy total proved reserves at December 31, 2010. Uinta Basin proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs at depths of 5,000 feet to deeper than 18,000 feet. QEP Energy owns interests in approximately 290,000 net leasehold acres in the Uinta Basin.

Rockies Legacy

The remainder of QEP Energy Rocky Mountain region leasehold interests, productive wells and proved reserves are distributed over a number of 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 contributed 18.7 Bcfe or 8% of 2010 production and comprised 298.5 Bcfe or 10% of QEP Energy total proved reserves at December 31, 2010. Exploration and development activity for 2011 includes wells in the Powder River, Greater Green River and Williston Basins.

QEP Energy has approximately 90,000 net acres of lease rights in the Williston Basin in western North Dakota where the company is targeting the Bakken and Three Forks formations. The true vertical depth to the top of the Bakken Formation ranges from approximately 9,500 feet to 10,000 feet across QEP Energy’s leasehold. The Three Forks Formation lies approximately 60 to 70 feet below the Middle Bakken Formation and is also a target for horizontal drilling. QEP Energy intends to drill or participate in 53 gross Bakken or Three Forks horizontal wells in 2011 compared to 29 gross wells in 2010. As of December 31, 2010, QEP Energy had two operated rigs drilling in the project area and had working interests in 55 gross producing Bakken or Three Forks wells in North Dakota compared to working interests in 26 gross wells at December 31, 2009.

 

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QEP FIELD SERVICES

QEP Field Services activities reported net income of $91.1 million in 2010 compared to $69.4 million in 2009, a 31% increase. QEP Field Services net income was $81.5 million in 2008. Net income increased in 2010 due to improved gathering margins driven by higher gathering volumes and higher processing margins. Net income decreased in 2009 compared to 2008 as the result of decreased processing margins and increased depreciation expense. Following is a summary of QEP Field Services’ financial and operating results:

 

     Year Ended December 31,     Change  
     2010     2009     2008     2010 vs. 2009     2009 vs. 2008  
     (in millions)  

QEP Field Services Operating Income

          

REVENUES

          

NGL sales

   $ 94.8      $ 71.9      $ 106.0      $ 22.9      $ (34.1

Processing

     35.2        32.6        31.0        2.6        1.6   

Gathering

     152.5        127.3        121.0        25.2        6.3   

Other gathering

     36.7        32.8        32.2        3.9        0.6   
                                        

Total Revenues

     319.2        264.6        290.2        54.6        (25.6

OPERATING EXPENSES

          

Processing

     11.9        10.3        10.2        1.6        0.1   

Processing plant shrinkage

     32.6        28.1        48.7        4.5        (20.6

Gathering

     37.6        36.6        36.1        1.0        0.5   

General and administrative

     31.6        25.0        23.7        6.6        1.3   

Property taxes

     4.4        4.6        2.6        (0.2     2.0   

Depreciation, depletion and amortization

     48.9        44.3        28.7        4.6        15.6   

Abandonment and impairments

     —          —          0.8        —          (0.8
                                        

Total Operating Expenses

     167.0        148.9        150.8        18.1        (1.9

Net loss from asset sales

     (1.6     (0.1     —          (1.5     (0.1
                                        

Operating Income

     150.6        115.6        139.4        35.0        (23.8
                                        

Interest and other income

     0.1        (0.2     —          0.3        (0.2

Income from unconsolidated affiliates

     2.8        2.6        1.2        0.2        1.4   

Interest expense

     (7.6     (6.0     (3.6     (1.6     (2.4
                                        

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

     145.9        112.0        137.0        33.9        (25.0

Income taxes

     (51.9     (40.0     (46.5     (11.9     6.5   
                                        

INCOME FROM CONTINUING OPERATIONS

     94.0        72.0        90.5        22.0        (18.5

Net income attributable to noncontrolling interest

     (2.9     (2.6     (9.0     (0.3     6.4   
                                        

NET INCOME ATTRIBUTABLE TO QEP FIELD SERVICES

   $ 91.1      $ 69.4      $ 81.5      $ 21.7      $ (12.1
                                        

Depreciation expense increased $4.6 million during 2010 compared with 2009 due to the addition of new facilities. Approximately 78% of Field Services 2010 net operating revenue was derived from fee-based contracts, compared to 82% in 2009.

Gathering

The primary driver of increased gathering margin (gathering revenue minus gathering expense) in 2010 was the transfer of the northwest Louisiana gathering system assets from QEP Energy to QEP Field Services in January 2010. The transfer of the northwest Louisiana gathering system is also the driver for the increase in system throughput volume along with increased drilling activity within the Haynesville Shale. Gathering margins also increased at the Black Fork Hub reflecting growing Pinedale production volumes and declining operating expenses.

 

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Following is a summary of QEP Field Services’ gathering related financial and operating results:

 

    

Year Ended

December 31,

    Change  
     2010     2009     2008    

2010 vs. 2009

    2009 vs. 2008  
     (in millions)  

Gathering Margin

          

Gathering

   $ 152.5      $ 127.3      $ 121.0      $ 25.2      $ 6.3   

Other gathering

     36.7        32.8        32.2        3.9        0.6   

Gathering (expense)

     (37.6     (36.6     (36.1     (1.0     (0.5
                                        

Gathering Margin

   $ 151.6      $ 123.5      $ 117.1      $ 28.1      $ 6.4   
                                        

Operating Statistics

          

Natural gas gathering volumes (in millions of MMBtu)

          

For unaffiliated customers

     276.8        301.2        278.3        (24.4     22.9   

For affiliated customers

     198.9        112.6        114.2        86.3        (1.6
                                        

Total Gas Gathering Volumes

     475.7        413.8        392.5        61.9        21.3   
                                        

Average gas gathering revenue (per MMBtu)

   $ 0.32      $ 0.31      $ 0.31      $ 0.01      $ —     

Processing

Processing margin (processing revenue minus processing expenses and processing plant shrinkage) increased in 2010 compared with 2009 due to improved NGL prices and lower natural gas (shrink) costs. The increase in processing volumes in 2010 was driven by increased throughput at QEP Field Services’ Stagecoach plant in eastern Utah.

Following is a summary of QEP Field Services’ processing related financial and operating results:

 

    

Year Ended

December 31,

    Change  
     2010     2009     2008    

2010 vs. 2009

   

2009 vs. 2008

 
     (in millions)  

Processing Margin

          

NGL sales

   $ 94.8      $ 71.9     $ 106.0     $ 22.9      $ (34.1

Processing (fee based)

     35.2        32.6       31.0       2.6        1.6  

Processing (expense)

     (11.9     (10.3 )     (10.2 )     (1.6     (0.1

Processing plant shrinkage (expense)

     (32.6     (28.1 )     (48.7 )     (4.5     20.6   
                                        

Processing Margin

   $ 85.5      $ 66.1      $ 78.1      $ 19.4      $ (12.0
                                        

Frac spread (NGL sales – Processing plant shrinkage)

   $ 62.2      $ 43.8      $ 57.3      $ 18.4      $ (13.5

Operating Statistics

          

Natural gas processing volumes

          

NGL sales (MMgal)

     100.2        101.6       89.5       (1.4     12.1   

Average NGL sales price (per gal)

   $ 0.95      $ 0.71     $ 1.18     $ 0.24      $ (0.47

Fee-based processing volumes (in millions of MMBtu)

          

For unaffiliated customers

     116.8        110.6       97.0       6.2        13.6  

For affiliated customers

     109.4        99.4       104.5       10.0        (5.1
                                        

Total Fee-Based Processing Volumes

     226.2        210.0       201.5       16.2        8.5  
                                        

Average fee-based processing revenue (per MMBtu)

   $ 0.16      $ 0.15     $ 0.14     $ 0.01      $ 0.01   
                                        

 

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QEP MARKETING

QEP Marketing net income was $6.7 million in 2010, a decrease of 21% compared to 2009 net income of $8.5 million. QEP Marketing net income was $22.1 million in 2008. The decreases in 2010 and 2009 were a result of lower marketing and storage margins due to an overall decrease in natural gas price volatility. Revenues from unaffiliated customers were $598.8 million in 2010 compared to $442.5 million in 2009, a 35% increase, the result of higher natural gas prices and increased sales volumes. The weighted-average natural gas sales price increased 20% in 2010 to $3.95 per MMBtu, compared to $3.29 per MMBtu in 2009. The gas sales volumes increased 7% in 2010 to 201.9 MMBtu compared to 189.3 MMBtu in 2009. Higher revenue was more than offset by increased cost of gas purchased from third-parties that was later resold.

CONSOLIDATED RESULTS BELOW OPERATING INCOME

Separation costs

QEP reported expenses of $13.5 million during 2010 related to the Spin-off of QEP Resources, Inc. from Questar Corporation on June 30, 2010. The expenses consisted primarily of QEP’s share of certain fees and expenses for financial, legal and tax advisory services and for severance expenses for terminated employees.

Loss on early extinguishment of debt

QEP reported $13.3 million in losses on early extinguishment of debt in 2010 related to the purchase of $638.0 million principal amount of senior notes and the termination of commitments under the $500.0 million term loan. The purchase of $638.0 million principal amount of senior notes in August 2010 was a result of QEP’s offer to purchase the notes related to the Spin-off pursuant to the change of control provisions in the senior notes’ indenture. As a result of the issuance of $625.0 million principal amount of senior notes in August 2010, all the outstanding debt under the term loan was repaid and commitments under the term loan were terminated.

Interest and Other Income

Interest and other income decreased $2.2 million in 2010 compared with 2009 due primarily to a valuation adjustment on pipe inventory. Interest and other income decreased $5.7 million in 2009 compared with 2008 due to less activity in sales of inventory.

Realized and unrealized gain (loss) on basis-only swaps

In the past, the Company has used basis-only swaps to manage the risk of widening basis differentials. Basis-only swaps do not qualify for hedge accounting. As of December 31, 2009, all of the Company’s basis-only swaps had been paired with NYMEX gas fixed-price swaps or price-collars and re-designated as cash flow hedges. Fair value changes occurring prior to re-designation were recorded in the Consolidated Statements of Income. Changes in the fair value of the derivative instruments subsequent to the re-designation were recorded in AOCI. Upon settlement, the portion of the settlement attributed to the period prior to re-designation is reported as an unrealized gain (loss) and offsets prior period’s impact on the Consolidated Statement of Income. The Company recognized unrealized gains of $121.7 million in 2010, and unrealized losses of $164.0 million in 2009 and $79.2 million in 2008. The Company realized losses of $121.7 million in 2010 and $25.6 million in 2009 on settlements of basis-only swaps, which were reported after operating income in the Consolidated Statements of Income.

Interest expense

Interest expense rose 20% in 2010 compared with 2009 and 14% in 2009 compared to 2008 due primarily to financing activities associated with the issuance of the new bonds in 2010, higher interest rates under QEP’s amended credit facility, and higher debt levels related to the purchase of natural gas development properties in northwest Louisiana in 2008.

 

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Income taxes

The Company’s effective combined federal and state income tax rate was 36.9% in 2010 compared with 35.3% in 2009 and 2008.

LIQUIDITY AND CAPITAL RESOURCES

QEP anticipates that its cash capital expenditures, which were $1,469.0 million in 2010, will be approximately $1,200.0 million in 2011. QEP expects to fund its 2011 capital expenditure budget primarily with cash flow from operations, supplemented with additional sources of liquidity, if needed, including bank financings, and proceeds from the issuance of long-term debt and/or equity securities. QEP’s ability to raise funds in the capital markets will be impacted by its financial condition, interest rates, market conditions, and industry conditions.

Operating Activities

Net cash provided by operating activities from continuing operations decreased 13% in 2010 compared to 2009. The decrease from 2009 compared to 2008 was 6%. Cash sources from operating assets and liabilities were lower in 2010 primarily due to reductions in accounts receivable during 2009 and a decrease in current federal income taxes payable due to bonus depreciation. Noncash adjustments to net income consisted primarily of depreciation, depletion and amortization, and deferred income taxes. Net cash provided by operating activities is presented below:

 

     Year Ended December 31,     Change  
     2010     2009      2008     2010 vs. 2009     2009 vs. 2008  
     (in millions)  

Net income

   $ 329.1      $ 296.1       $ 594.5      $ 33.0      $ (298.4

Noncash adjustments to net income

     741.3        782.3         692.6        (41.0     89.7   

Changes in operating assets and liabilities

     (72.9     71.0         (62.4     (143.9     133.4   
                                         

Net cash provided from continuing operating activities

   $ 997.5      $ 1,149.4       $ 1,224.7      $ (151.9   $ (75.3
                                         

Investing Activities

A comparison of capital expenditures, including exploratory dry hole expense, from continuing operations in 2010 and 2009 and a forecast for 2011 are shown in the table below:

 

     Year Ended December 31,  
     2011
Forecast
     2010      2009  
     (in millions)  

QEP Energy

   $ 1,050.0       $ 1,205.0       $ 1,108.6   

QEP Field Services

     150.0         262.1         88.3   

QEP Marketing and other

     —           1.9         1.5   
                          

Total cash capital expenditures from continuing operations

   $ 1,200.0         1,469.0         1,198.4   
              

Changes in accruals

        16.9         (90.0
                    

Total accrued capital expenditures from continuing operations

      $ 1,485.9       $ 1,108.4   
                    

Net cash used in investing activities on the Consolidated Statements of Cash Flows also includes proceeds from the disposition of assets of $25.6 million in 2010 and $14.2 million in 2009, as well as reductions in notes receivable of $52.9 million and $37.8 million in 2010 and 2009, respectively.

 

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QEP Energy

QEP Energy capital expenditures were higher in 2010 compared to 2009 due to an increased drilling program in 2010. The 2010 net drilling-success rate was 99.0%. There were 191 gross wells in progress at year-end.

QEP Field Services

QEP Field Services increased investment in its gathering, processing and treating facilities to expand capacity in western Wyoming, eastern Utah and northwest Louisiana.

Financing Activities

For 2010, net cash used in investing activities of $1,390.5 exceeded net cash provided by operating activities of $997.5 by $393.0 million. During 2010, the Company increased its drilling activities primarily to hold acreage by establishing production on expiring leases. In 2009, as a result of the economic downturn, the Company limited capital expenditures to approximate internally generated cash flow. In 2009, net cash provided by operating activities of $1,149.4 million exceeded net cash used in investing activities of $1,146.4 million by $3.0 million reflecting the strategy.

For 2010, long-term debt increased by a net change of $123.6 million while short-term debt increased by $19.2 million. In 2009, long-term debt increased by a net change of $47.0 million and short-term debt decreased by a net change of $50.1 million. At December 31, 2010, long-term debt consisted of $400.0 million outstanding under QEP’s revolving credit facility and $1,130.8 million in senior notes (including $6.1 million of net original issue discount), which includes $58.5 million of senior notes that mature in March 2011. All intercompany loans between Questar and QEP, which have been historically reported as notes payable in the Consolidated Balance Sheets, were repaid on June 30, 2010, in conjunction with the Spin-off. QEP’s consolidated capital structure consisted of 34% combined short- and long-term debt and 66% common shareholders’ equity at December 31, 2010 and 2009.

In June 2010, in conjunction with the Spin-off, QEP amended its existing revolving credit agreement. The amendment increased the amount of commitments from $800.0 million to $1.0 billion, increased commitment fees, increased the applicable margin used in calculating interest rates and added financial covenants that limit the amount of funded indebtedness the Company may incur, as well as modifying other immaterial provisions of the agreement. In addition, QEP entered into a $500.0 million, 364-day term loan agreement (term loan) with substantially the same initial pricing and terms as its revolving credit agreement.

In August 2010, the Company purchased $638.0 million principal amount of its senior notes and paid required premium and accrued interest pursuant to the requirement in the notes’ indenture relating to a change of control. The Company used cash on hand and proceeds from its $1.0 billion revolving credit facility and $500.0 million term loan to purchase all of the tendered notes. Subsequent to the purchase of the tendered notes, the Company issued $625.0 million principal amount of senior notes due 2021. The notes were issued at a discount, resulting in gross proceeds of $619.2 million which were used to pay fees and expenses associated with the issuance and to refinance a portion of the indebtedness incurred under the term loan and revolving credit facilities to purchase the tendered senior notes. Upon repayment of the term loan, commitments under the term loan were terminated. The Company’s senior notes outstanding as of December 31, 2010 totaled $1,137.0 million in principal and are comprised of five issues as follows:

 

   

$58.5 million 7.50% Senior Notes due March 2011

 

   

$176.8 million 6.05% Senior Notes due September 2016

 

   

$138.6 million 6.80% Senior Notes due April 2018

 

   

$138.0 million 6.80% Senior Notes due March 2020

 

   

$625.0 million 6.875% Senior Notes due March 2021

 

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At February 18, 2011 QEP had $441.0 million outstanding under its revolving credit facility and $5.6 million of letters of credit issued. At December 31, 2010, accounting for the outstanding letters of credit, QEP had unused capacity of $594.4 million on its revolving-credit facility.

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, QEP enters into a variety of contractual cash obligations and other commitments. The following table summarizes the significant contractual cash obligations as of December 31, 2010:

 

     Payments Due by Year  
     Total      2011      2012      2013      2014      2015      After
2015
 
     (in millions)  

Long-term debt

   $ 1,536.9       $ 58.5       $ —         $ 400.0       $ —         $ —         $ 1,078.4   

Interest on fixed-rate long-term debt

     652.6         73.2         72.5         72.5         72.5         72.5         289.4   

Drilling contracts

     58.1         54.0         4.1         —           —           —           —     

Transportation contracts

     447.6         45.4         45.2         43.6         42.5         42.4         228.5   

Operating leases

     15.1         5.0         4.5         3.4         1.0         1.1         0.1   
                                                              

Total

   $ 2,710.3       $ 236.1       $ 126.3       $ 519.5       $ 116.0       $ 116.0       $ 1,596.4   
                                                              

Critical Accounting Policies, Estimates and Assumptions

QEP’s significant accounting policies are described in Note 1 to the consolidated financial statements included in Item 8 of Part II of its 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, economic assumptions relating to commodity prices, operating expenses, 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. See Note 16 to the consolidated financial statements included in Item 8 of this Report on Form 10-K for more information on the Company’s estimated proved reserves.

Successful Efforts Accounting for Gas and Oil Operations

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

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

 

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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.

QEP Energy engages an independent reservoir engineering consultant 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 Derivative Contracts

The Company uses derivative contracts, typically fixed-price swaps and costless collars, to hedge against a decline in the realized prices of its natural 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 AOCI depending on the structure of the derivative. The Company has historically structured the majority of its energy derivative instruments as cash flow hedges as defined in ASC 815 “Derivatives and Hedging.” Changes in the fair value of cash flow hedges are recorded on the balance sheet and in AOCI 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. Changes in the fair value of derivative contracts that do not qualify for hedge accounting are included as part of operating income in the Consolidated Statement of Income.

Revenue Recognition

Revenues are recognized in the period that services are provided or products are delivered. QEP Energy 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 QEP Energy has an imbalance in excess of its share of remaining reserves in an underlying property. QEP Marketing presents revenues on a gross revenue basis. QEP Marketing 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

There have been no recent accounting pronouncements that were adopted in 2010 or are under consideration that would have a material impact on QEP’s results of operations or financial condition.

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP’s primary market-risk exposure arises from changes in the market price for natural gas, oil and NGL, and volatility in interest rates. QEP Energy and QEP Marketing have long-term contracts for pipeline capacity and are obligated to pay for transportation services with no guarantee that they will be able to fully utilize the contractual capacity of these transportation commitments.

Commodity Price Risk Management

QEP’s subsidiaries use commodity-price derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, these same arrangements typically limit future gains from favorable price movements.

As of December 31, 2010, QEP held commodity-price derivative contracts for 247.5 million MMBtu of natural gas and 1.1 million barrels of oil. As of December 31, 2009, QEP held derivative contracts for 409.6 million MMBtu of natural gas and 2.7 million barrels of oil. A table reconciling the net fair value of the Company’s derivative positions for equity production as of December 31, 2010, is shown below:

 

     Cash flow
Hedges
    Basis-only
Swaps
    Total  
      
     (in millions)  

Net fair value of gas- and oil-derivative contracts outstanding at Dec. 31, 2009

   $ 138.5      $ (239.4   $ (100.9

Contracts realized or otherwise settled

     (348.2     121.7        (226.5

Change in gas and oil prices on futures markets

     564.4        —          564.4   

Contracts added

     1.5        —          1.5   
                        

Net Fair Value Of Gas- and Oil-Derivative Contracts Outstanding at Dec. 31, 2010

   $ 356.2      $ (117.7   $ 238.5   
                        

A table of the net fair value of gas- and oil-derivative contracts that are scheduled to settle over the next three years as of December 31, 2010, is shown below. Derivatives representing about 50% of the net fair value will settle in the next 12 months and will be reclassified from AOCI:

 

     Cash flow
Hedges
     Basis-only
Swaps
    Total  
       
     (in millions)  

Contracts maturing by Dec. 31, 2011

   $ 235.7       $ (117.7   $ 118.0   

Contracts maturing between Jan. 1, 2012 and Dec. 31, 2012

     59.6         —          59.6   

Contracts maturing between Jan. 1, 2013 and Dec. 31, 2013

     60.9         —          60.9   
                         

Net Fair Value Of Gas- and Oil-Derivative Contracts Outstanding at Dec. 31, 2010

   $ 356.2       $ (117.7   $ 238.5   
                         

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

 

     At December 31,  
     2010      2009  
     (in millions)  

Net fair value – asset (liability)

   $ 238.5       $ (100.9

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

     356.2         174.2   

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

     132.1         (375.8

 

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Credit Risk

QEP requests credit support and, in some cases, financial guarantees, letters of credit or prepayment from companies that pose unfavorable credit risks. The Company’s five largest customers are Sempra Energy Trading Corp., Chevron USA Inc., Enterprise Products Operating, Macquarie Energy LLC. and BP Energy Company. Sales to these companies accounted for 27% of QEP revenues before elimination of intercompany transactions in 2010, and their accounts were current at December 31, 2010.

Interest-Rate Risk

The Company’s ability to borrow and the rates quoted by lenders can be adversely affected by the illiquid credit markets as described in Item 1A. Risk Factors of Part I of this Annual Report on Form 10-K. The Company’s credit facility has floating interest rates and as such, exposes QEP to interest rate risk. If interest rates were to increase 10% over their average 2010 and 2009 levels and at our average level of borrowing for those years, our annualized interest expense would increase by $0.5 million and $0.3 million, respectively, or less than 1% in either year.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial Statements:

 

     Page No.  

Report of Independent Registered Public Accounting Firm

     48   

Consolidated Statements of Income, three years ended December 31, 2010

     49   

Consolidated Balance Sheets at December 31, 2010 and 2009

     50   

Consolidated Statements of Equity, three years ended December 31, 2010

     52   

Consolidated Statements of Cash Flows, three years ended December 31, 2010

     53   

Notes Accompanying the Consolidated Financial Statements

     54   

Financial Statement Schedule:

  

Valuation and Qualifying Accounts, for the three years ended December 31, 2010

     87   

All other schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or Notes thereto.

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of

QEP Resources, Inc.

We have audited the accompanying consolidated balance sheets of QEP Resources, Inc. as of December 31, 2010 and 2009, and the related consolidated statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of QEP Resources, Inc. at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, 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 consolidated financial statements, during 2009, the Company adopted a new accounting standard relating to the presentation of noncontrolling interests in consolidated subsidiaries and the Company adopted new oil and gas reserve estimation and disclosure requirements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), QEP Resources Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2011, expressed an unqualified opinion thereon.

Ernst & Young LLP

Denver, Colorado

February 25, 2011

 

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QEP RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

 

     Year Ended December 31,  
     2010     2009     2008  
     (in millions, except per-share amounts)  

REVENUES

      

Natural gas sales

   $ 1,086.9      $ 1,103.9      $ 1,147.7   

Oil and NGL sales

     238.9        158.5        237.5   

Gathering, processing and other

     322.6        268.3        297.0   

Marketing sales

     598.0        441.8        636.6   
                        

Total Revenues

     2,246.4        1,972.5        2,318.8   
                        

OPERATING EXPENSES

      

Marketing purchases

     589.3        427.8        604.6   

Lease operating expenses

     125.0        125.5        124.0   

Gathering, processing and other

     83.2        76.2        96.2   

General and administrative

     107.2        91.7        78.1   

Separation costs

     13.5        —          —     

Production and property taxes

     82.5        62.9        106.9   

Depreciation, depletion and amortization

     643.4        559.1        361.5   

Exploration expenses

     23.0        25.0        29.3   

Abandonment and impairment

     46.1        20.3        45.4   
                        

Total Operating Expenses

     1,713.2        1,388.5        1,446.0   

Net gain from asset sales

     12.1        1.5        60.4   
                        

OPERATING INCOME

     545.3        585.5        933.2   

Interest and other income

     2.3        4.5        10.2   

Income from unconsolidated affiliates

     3.0        2.7        1.7   

Unrealized and realized (loss) on basis-only swaps

     —          (189.6     (79.2

Loss from early extinguishment of debt

     (13.3     —          —     

Interest expense

     (84.4     (70.1     (61.7
                        

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

     452.9        333.0        804.2   

Income taxes

     (167.0     (117.6     (283.6
                        

INCOME FROM CONTINUING OPERATIONS

     285.9        215.4        520.6   

Discontinued operations, net of income tax

     43.2        80.7        73.9   
                        

NET INCOME

     329.1        296.1        594.5   

Net income attributable to noncontrolling interest

     (2.9     (2.6     (9.0
                        

NET INCOME ATTRIBUTABLE TO QEP

   $ 326.2      $ 293.5      $ 585.5   
                        

Earnings Per Common Share Attributable To QEP

      

Basic from continuing operations

   $ 1.61      $ 1.23      $ 2.96   

Basic from discontinued operations

     0.25        0.46        0.43   
                        

Basic total

   $ 1.86      $ 1.69      $ 3.39   
                        

Diluted from continuing operations

   $ 1.60      $ 1.21      $ 2.90   

Diluted from discontinued operations

     0.24        0.46        0.42   
                        

Diluted total

   $ 1.84      $ 1.67      $ 3.32   
                        

Weighted-average common shares outstanding

      

Used in basic calculation

     175.3        174.1        172.8   

Used in diluted calculation

     177.3        176.3        176.1   

See notes accompanying the consolidated financial statements

 

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QEP RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

 

     December 31,  
     2010      2009  
     (in millions)  

ASSETS

     

Current Assets

     

Cash and cash equivalents

   $ —         $ 19.3   

Notes receivable from Questar

     —           52.9   

Accounts receivable, net

     269.9         219.8   

Fair value of derivative contracts

     257.3         128.2   

Inventories, at lower of average cost or market

     

Gas and oil storage

     16.4         17.5   

Materials and supplies

     65.4         74.3   

Prepaid expenses and other

     45.2         29.2   

Deferred income taxes – current

     —           21.2   

Current assets of discontinued operations

     —           42.8   
                 

Total Current Assets

     654.2         605.2   
                 

Property, Plant and Equipment – successful efforts method of accounting for gas and oil properties

     

Proved properties

     6,874.3         5,721.5   

Unproved properties, not being depleted

     322.0         389.6   

Midstream field services

     1,360.5         1,037.5   

Marketing and other

     44.5         42.4   
                 

Total Property, Plant and Equipment

     8,601.3         7,191.0   
                 

Less accumulated depreciation, depletion and amortization

     

Exploration and production

     2,454.4         1,890.9   

Midstream field services

     244.6         198.7   

Marketing and other

     12.3         10.1   
                 

Total Accumulated Depreciation, Depletion and Amortization

     2,711.3         2,099.7   
                 

Net property, plant and equipment of discontinued operations

     —           593.9   
                 

Net Property, Plant and Equipment

     5,890.0         5,685.2   
                 

Investment in unconsolidated affiliates

     44.5         43.9   

Other Assets

     

Goodwill

     59.6         60.1   

Fair value of derivative contracts

     120.8         61.2   

Other noncurrent assets

     16.2         10.0   

Noncurrent assets of discontinued operations

     —           15.8   
                 

Total Other Assets

     196.6         147.1   
                 

TOTAL ASSETS

   $ 6,785.3       $ 6,481.4   
                 

 

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LIABILITIES AND EQUITY

 

     December 31,  
     2010      2009  
     (in millions)  

Current Liabilities

     

Checks outstanding in excess of cash balances

   $ 19.5       $ —     

Notes payable to Questar

     —           39.3   

Account payable and accrued expenses

     332.2         313.0   

Federal income taxes payable

     —           13.5   

Production and property taxes

     18.9         34.2   

Interest payable

     28.1         26.3   

Fair value of derivative contracts

     139.3         149.7   

Deferred income taxes – current

     27.8         —     

Current portion long-term debt

     58.5         —     

Current liabilities of discontinued operations

     —           88.9   
                 

Total Current Liabilities

     624.3         664.9   
                 

Long-term debt

     1,472.3         1,348.7   

Deferred income taxes

     1,377.7         1,175.8   

Asset retirement obligations

     148.3         124.7   

Fair value of derivative contracts

     0.3         140.6   

Other long-term liabilities

     99.3         42.5   

Noncurrent liabilities of discontinued operations

     —           175.5   

Commitments and contingencies – Note 11

     

EQUITY

     

Common stock – par value $0.01 per share;

     

500.0 million shares authorized; 175.9 million and 174.6 million shares issued and outstanding at December 31, 2010 and 2009, respectively.

     1.8         1.7   

Additional paid-in capital

     394.2         126.8   

Retained earnings

     2,420.0         2,538.2   

Accumulated other comprehensive income

     194.3         87.1   
                 

Total Common Shareholders’ Equity

     3,010.3         2,753.8   

Noncontrolling interest

     52.8         54.9   
                 

Total Equity

     3,063.1         2,808.7   
                 

TOTAL LIABILITIES AND EQUITY

   $ 6,785.3       $ 6,481.4   
                 

See notes accompanying the consolidated financial statements

 

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QEP RESOURCES, INC.

CONSOLIDATED STATEMENTS OF EQUITY

 

    Common
Stock
    Additional
Paid-in
Capital
    Retained
Earnings
    Accum. Other
Comprehensive
Income (Loss)
    Non-
controlling
Interest
    Comprehensive
Income

(Loss)
 
    (in millions)   

Balances at January 1, 2008

  $ 1.7      $ 133.5      $ 1,693.9      $ 31.0      $ —        $ —     

2008 net income

    —          —          585.5        —          9.0        594.5   

Dividends paid

    —          —          (17.3     —          —          —     

Share-based compensation

    —          11.0        —          —          —          —     

Consolidation of noncontrolling interest

    —          —          —          —          29.8        —     

Distribution of noncontrolling interest

    —          —          —          —          (9.3     —     

Other comprehensive income

    —          —          —          —          —          —     

Change in unrealized fair value of derivatives

    —          —          —          494.0        —          494.0   

Income taxes

    —          —          —          (183.4     —          (183.4
                 

Total comprehensive income

    —          —          —          —          —        $ 905.1   
                                               

Balances at December 31, 2008

    1.7        144.5        2,262.1        341.6        29.5     
                                         

2009 net income

    —          —          293.5        —          2.6      $ 296.1   

Dividends paid

    —          —          (17.4     —          —          —     

Share-based compensation

    —          13.9        —          —          —          —     

Consolidation of noncontrolling interest

    —          (28.5     —          —          28.5        —     

Tax on equity adjustment

    —          (3.1     —          —          —          —     

Distribution of noncontrolling interest

    —          —          —          —