form10k.htm


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, 2011

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
x
 
Accelerated filer
¨
         
Non-accelerated filer
o
(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, 2011): $7,399,937,572.
 
At January 31, 2012, there were 177,498,486 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
 
   
Page No.
   
            3
            3
            4
     
 
PART I
 
     
Item 1.
            7
 
           7
 
            8
 
           9
 
           11
 
            11
 
            11
     
Item 1A.  
            13
     
Item 1B.
            21
     
Item 2.
            21
 
            21
 
            29
 
            29
     
Item 3.
            29
     
Item 4.
            30
     
 
PART II
 
     
Item 5.
            31
     
Item 6.
            33
     
Item 7.
            35
     
Item 7A.
            56
     
Item 8.
            59
     
Item 9.
            97
     
Item 9A.
            98
     
Item 9B.
            98
     
 
PART III
 
     
Item 10.
            99
     
Item 11.
            99
     
Item 12.
            99
     
Item 13.
            99
     
Item 14.
            99
     
 
PART IV
 
     
Item 15.
            99
     
 
            103
 
 
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. We 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:
 
 
QEP’s growth strategies;
 
 
plans to drill or participate in wells;
 
 
future expenses and operating costs;
 
 
belief that QEP has one of the lowest cash cost structures among its peers;
 
 
the outcome of contingencies such as legal proceedings;
 
 
expected contributions to the Company’s retirement plans;
 
 
results from planned drilling operations and production operations;
 
 
amount and allocation of forecasted capital expenditures and plans for funding capital expenditures;
 
 
impact of recently issued accounting pronouncements;
 
 
the amount and timing of the settlement of derivative contracts;
 
 
the significance of Adjusted EBITDA as a measure of cash flow and liquidity;
 
 
the ability of QEP to use derivative instruments to manage commodity price risk;
 
 
the ability to secure long-term gathering, processing and treating contracts from third parties as required to fully utilize the Company’s midstream assets;
 
 
operation of the Company’s Blacks Fork II and other processing plants at assumed capacities;
 
 
QEP’s ability to develop reserves and grow production as necessary to satisfy delivery commitments and our ability to purchase natural gas, crude oil and NGL’s in the market to cover any shortfalls;
 
 
payment of dividends;
 
 
plans to hedge a portion of forecasted production;
 
 
conversion of proved undeveloped reserves to proved developed reserves;
 
 
acquisition strategy; and
 
 
growth strategy.
 
 
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;
 
 
changes in natural gas, oil and NGL prices;
 
 
general economic conditions, including the performance of financial markets and interest rates;
 
 
drilling results;
 
 
shortages of oilfield equipment, services and personnel;
 
 
operating risks such as unexpected drilling conditions;
 
 
weather conditions;
 
 
changes in maintenance and construction costs, including possible inflationary pressures;
 
 
changes in industry trends;
 
 
the availability and cost of debt financing;
 
 
changes in laws or regulations, including the implementation of the Dodd-Frank Act;
 
 
actions, or inaction, by federal, state, local or tribal governments; 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.
 
cushion gas  Volume of gas that must remain in a storage facility to provide the required pressure to extract the stored or working gas volumes.
 
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.
 
 
dry hole  A well drilled or junked and abandoned and found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of production exceed expenses and taxes.
 
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.
 
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.
 
IFNPCR   Inside FERC monthly settlement index for the Northwest Pipeline Corp. Rocky Mountains.
 
IFPEPL  Inside FERC monthly settlement index for the Panhandle Eastern Pipeline Company.
 
M  Thousand.
 
MM  Million.
 
Midstream  Gas gathering, compression, treating, processing, and transmission assets and activities that are non-jurisdictional. Also includes certain oil and produced water gathering systems and related commercial activities.
 
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 the gross wells or acres.
 
NYMEX  The New York Mercantile Exchange.
 
NYMEX  WTI The price of West Texas Intermediate crude oil on 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).
 
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.
 
 
FORM 10-K
ANNUAL REPORT 2011
 
PART I
 
ITEM 1. BUSINESS
 
Nature of Business
 
QEP Resources, Inc. (QEP or the Company), is a holding company with three major lines of business – gas and oil exploration and production, midstream field services, and energy marketing –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, compression and treating services for affiliates and third parties; and
 
 
QEP Marketing Company (QEP Marketing) markets affiliate and third-party natural gas and oil, provides risk-management services, and owns and operates an underground gas-storage reservoir.
 
QEP operates in the Northern (formerly referred to as the Rocky Mountain Region) and Southern (formerly referred to as the Midcontinent Region) 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:
Reincorporation Merger and Spin-off from Questar
 
Effective May 18, 2010, Questar Market Resources Inc., (Market Resources), then a wholly owned, public 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. 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 common stock for each share of Questar common stock held at the close of business on the record date. In connection with the Spin-off, 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 2 to the consolidated financial statements in Item 8 of this Annual Report on Form 10-K.
 
 
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:
 
 
·
Operate in a safe and environmentally responsible manner
 
·
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 plays in which we operate
 
·
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 QEP Energy production to maximize value
 
·
Utilize commodities derivatives to reduce the impact of a decline in the prices of our natural gas, crude oil or NGL and to lock in acceptable cash flows to support future capital expenditures
 
·
Attract and retain the best people
 
·
Maintain a strong balance sheet and financial flexibility that allows us to take advantage of both organic growth and acquisition opportunities
 
EXPLORATION AND PRODUCTION – QEP Energy Company
 
General: QEP Energy is actively involved in several of North America’s most important hydrocarbon resource plays. For 2012, QEP plans to allocate approximately 88% of its capital budget to QEP Energy. The following map illustrates the location of the Company’s significant exploration and production activities, our Northern and Southern Regions described elsewhere in this report, and related reserve and production data:
QEP’s exploration and production activities are conducted through QEP Energy, which generated approximately 76%, 81%, and 85% of the Company’s Adjusted EBITDA during the years ended December 31, 2011, 2010 and 2009, respectively. QEP Energy operates in two core regions – the Northern Region (including the states of Wyoming, Utah, Colorado, New Mexico and North Dakota) and the Southern Region (including the states of Oklahoma, Texas and Louisiana). The Southern Region contributed approximately 56% of 2011 production while the Northern Region contributed the remaining 44%. QEP Energy reported 3,614 Bcfe of estimated proved reserves as of December 31, 2011, up from 3,031 Bcfe at the end of 2010. Of those estimated proved reserves, approximately 64%, or 2,312 Bcfe, were located in the Northern Region at December 31, 2011, compared to 61% or 1,860 Bcfe at December 31, 2010. The remaining 36%, or 1,302 Bcfe at December 31, 2011, were located in the Southern Region, compared to 39% or 1,171 Bcfe at December 31, 2010. Approximately 54% of the proved reserves reported by QEP Energy at year end 2011 were developed, while 46% were categorized as proved undeveloped. Approximately 24% of the total proved reserves at December 31, 2011 were comprised of crude oil and NGL up from 14% at December 31, 2010.
 
 
QEP Energy has a large inventory of identified development drilling locations, primarily on the Pinedale Anticline in western Wyoming; the Haynesville/Cotton Valley area in northwestern Louisiana; the Midcontinent area with properties primarily in Oklahoma and Texas; the Uinta Basin in eastern Utah; and the Rockies Legacy, which includes the Bakken/Three Forks area in western North Dakota and other properties in Wyoming. QEP Energy continues to conduct exploratory drilling to determine the commerciality of its inventory of unproven 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 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 vertical depths that generally range between 10,000 and 14,000 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.
 
Competition and Customers: QEP Energy faces competition in every part of its business, including the acquisition of producing leasehold and wells 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 undeveloped 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 extensive 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 in air and water emissions and discharges incidental to gas and oil drilling, completion and production. QEP Energy is also subject to various conservation matters, including 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. Currently, all well construction activities, including hydraulic fracture stimulation, are regulated by state agencies that review and approve all aspects of natural gas and oil well design and operation. Most of QEP Energy’s leasehold acreage in the Northern 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.
 
See also “Risk Factors – Risk Related to Regulation.”
 
MIDSTREAM FIELD SERVICES – QEP Field Services Company
 
General: QEP invests in midstream (gathering, processing and treating) systems to complement its natural gas, oil and NGL operations in regions where QEP Energy has production. Through ownership and operation of these facilities, QEP is able to better manage the timing and costs associated with bringing on new production and enhance the value received for gathering, processing and treating the Company’s production. In addition, QEP’s midstream business also provides midstream services to third-party customers, including major and independent producers. QEP generates revenues from its midstream activities through a variety of agreements including fixed-fee, percent-of-proceeds and keep-whole agreements. For 2012, QEP plans to allocate approximately 12% if its capital budget to QEP Field Services.
 
 
The following map illustrates QEP Field Services areas of operations and the locations corresponding with QEP Energy’s operating areas:
QEP Field Services generated approximately 23%, 18% and 14% of the Company’s Adjusted EBITDA in the years ended December 31, 2011, 2010 and 2009, respectively. QEP Field Services owns various natural gas gathering, treating and processing facilities in the Northern and Southern Regions as well as 78% of Rendezvous Gas Services, LLC, (RGS), a partnership that operates gas gathering facilities in western Wyoming. 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. QEP Field Services also owns 38% of Uintah Basin Field Services, LLC (UBFS) and 50% of Three Rivers Gathering, LLC (Three Rivers). These two partnerships operate natural gas gathering facilities in eastern Utah.
 
Fee-based gathering and processing revenues were 70%, 78% and 82% of QEP Field Services’ net operating revenues (revenues less plant shrink and transportation costs) during the years ended December 31, 2011, 2010 and 2009, respectively. Approximately 35%, 36%, and 43% of QEP Field Services’ 2011, 2010 and 2009 net gas processing revenues (processing revenues less plant shrink and transportation costs) 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.
 
Competition and Customers: QEP Field Services faces regional competition with varying competitive factors in each basin. QEP Field Service’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.
 
Regulation: QEP Field Services’ construction and operation activities are subject to various local, state and federal rules and regulations. Most of these rules and regulations are administered by the federal Department of Transportation (DOT), the Occupational Safety and Health Administration (OSHA), and the Environmental Protection Agency (EPA). Many of QEP’s systems in the Northern Region are constructed and operated on public lands owned by the United States and administered by the Bureau of Land Management (BLM). Construction and operation of facilities on non-public land may also be subject to various regulations administered by state, tribal or local authorities.
 
Section 1(b) of the Natural Gas Act exempts gathering activities from regulation or jurisdiction by the Federal Energy Regulatory Commission (FERC). QEP owns, or holds interests in, a number of pipelines that it believes meet the tests FERC has used to determine a pipeline system’s status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining jurisdictional status of our gathering systems, so the distinction between non-jurisdictional gathering and FERC-regulated transmission pipelines may from time-to-time be the subject of disputes and litigation. QEP therefore cannot guarantee that the jurisdictional status of its gathering systems will remain unchanged. Several of QEP’s facilities have been determined to be under FERC jurisdiction and as such are subject to specific regulations regarding interstate transmission facilities and activities, including but not limited to rates charged for transmission, open access/non-discrimination, and public daily capacity and flow reporting requirements. QEP’s gas gathering systems are not subject to state utility regulations.
 
 
Additional rules and regulations pertaining to QEP Field Services activities are adopted from time to time. QEP cannot predict what impact, if any, such rules and regulations might have on its operations, but QEP may be forced to incur additional capital expenditures and/or increased operating costs as a result of such changes.
 
See also “Risk Factors – Risk Related to Regulation.”
 
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 Adjusted EBITDA in the years ended December 31, 2011, 2010  and 2009, respectively. 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, owns and 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. QEP Marketing sells NGL volumes from its Clear Creek storage facility to a refiner. 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, on behalf of QEP Energy and QEP Field Services, using fixed-price swaps or collars to secure a known price or price floor 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.
 
Regulation: The U.S. Commodities Future Trading Commission, which has regulatory authority over swap transactions under the Dodd-Frank Act, has adopted various rules which impose compliance requirements upon QEP Marketing’s derivatives trading practices. See also “Risk Factors – Risks Related to Regulation.”
 
FERC has jurisdiction over the operation of QEP Marketing’s Clear Creek storage facility, through the Clear Creek Storage Company LLC subsidiary in which QEP Marketing is the sole member, by virtue of the facility being connected to interstate pipelines (also subject to FERC jurisdiction) at both its inlet and outlet. Clear Creek is subject to specific FERC regulations governing interstate transmission facilities and activities, including but not limited to rates charges for transmission, open access/non-discrimination, and public disclosure via an electronic bulletin board of daily capacity and flows.
 
Employees
 
At December 31, 2011, QEP Resources, Inc. had 876 employees compared to 823 employees at December 31, 2010. None of QEP’s employees are represented by unions or covered by collective bargaining agreements.
 
Executive Officers of the Registrant
 
The name, age, period of service, title and business experience of each of QEP’s executive officers as of February 24, 2012, are listed below:
 
Charles B. Stanley
53
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
53
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
53
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
51
Senior Vice President – Field Services (2010 to present). Previous title with Questar: Vice President, Questar Gas Management (2005 to 2010).
     
Eric L. Dady
57
Vice President and General Counsel, QEP (2010 to present). Previous title with Questar: General Counsel Market Resources (2005 to 2010).
     
Abigail L. Jones
51
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.
 
 
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 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, NGL and related commodities;
 
 
the activities of the Organization of Petroleum Exporting Countries;
 
 
domestic and global economic conditions;
 
 
regional price differences resulting from available pipeline transportation capacity or local demand;
 
 
terrorist attacks on production or transportation assets;
 
 
the level of imports of, and the price of, foreign natural gas, oil and NGL;
 
 
the potential long-term impact of an abundance of natural gas from unconventional sources on the global gas supply;
 
 
domestic political developments and actions;
 
 
weather conditions;
 
 
domestic government regulations and taxes, including regulations or legislation relating to climate change or natural gas and oil exploration and production activities;
 
 
technological advances affecting energy consumption and energy supply;
 
 
conservation efforts;
 
 
the price, availability and acceptance of alternative fuels, including coal, nuclear energy and biofuels;
 
 
demand for electricity as well as natural gas used for fuel for electricity generation;
 
 
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 or a reduction in the carrying value of goodwill. During the fourth quarter of 2011, QEP recorded a non-cash price-related impairment charge of $195.2 million on some of QEP Energy's mature, dry gas, and higher cost properties in both the Northern and Southern Regions. The impairment charge related to the reduced value of these areas resulting from lower natural gas prices and the current forward curve for natural gas prices. See Item 8, footnote 1, “Summary of Significant Accounting Policies” for additional information.
 
Slower economic growth rates in the US may materially adversely impact QEP’s operating results. The US and other economies are recovering from a global financial crisis and recession that began in 2008. Growth has resumed but has been modest and at an unsteady rate.  There are likely to be significant long-term effects resulting from the financial crisis and recession, including a future global economic growth rate that is slower than what was experienced in the years leading up to the crisis, and more volatility may occur before a sustainable, yet lower, growth rate is achieved.  In addition, the Organization for Economic Cooperation and Development (OECD) has encouraged countries with large federal budget deficits, such as the US, to initiate deficit reduction measures. Such measures, if they are undertaken too rapidly, could further undermine economic recovery and slow growth by reducing demand.  Global economic growth drives demand for energy from all sources, including fossil fuels.  A lower future economic growth rate is likely to result in decreased demand growth for QEP’s natural gas, oil and NGL production. A decrease in demand, excluding changes in other factors, could potentially result in lower commodity prices, which would reduce QEP’s cash flows from operations and its profitability.
 
 
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 natural gas and oil production volumes from QEP wells typically decline by 60% or more in the first year of operation and continue to decline over the economic life of the well, QEP must continue to invest significant capital to find, develop and acquire gas and oil reserves to replace those depleted by production.
 
Gas and oil reserve estimates are imprecise and subject to revision. 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 and availability of qualified and experienced field personnel to drill wells and conduct field operations, including 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.
 
QEP’s 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;
 
 
plant, pipeline, and other facility 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, 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 accident or other 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 once realized 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 coverage and amounts of insurance that it carries are 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.
 
Lack of availability of pipeline capacity could impact results of operations. The lack of availability of satisfactory oil, natural gas and NGL transportation arrangements may hinder QEP’s access to oil, NGL and natural gas markets or delay production from its wells. QEP’s ability to market its production depends in substantial part on the availability and capacity of pipelines owned and operated by third parties. Although QEP has some contractual control over the transportation of its production through firm transportation arrangements, third-party systems may be temporarily unavailable due to market conditions, mechanical failures, or other reasons. 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 production shut in, reducing profitability. Furthermore, if QEP were required to shut in wells, it might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain its leases. If pipeline quality requirements change, QEP might be required to install additional treating or processing equipment, which could also increase costs. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could also adversely affect QEP’s ability to transport natural gas and oil.
 
The fees charged to third parties under our gathering and processing agreements may not escalate sufficiently to cover increases in costs, or the agreements may not be renewed or may be suspended in some circumstances.  QEP’s costs may increase at a rate greater than the fees it charges to third parties for gathering, treating and processing services. Furthermore, third parties may not renew their contracts with QEP. Additionally, some third parties' obligations under their agreements with QEP may be permanently or temporarily reduced due to certain events, some of which are beyond QEP’s control, including force majeure events wherein the supply of either natural gas, oil or NGLs are curtailed or cut off. Force majeure events include (but are not limited to): revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, earthquakes, acts of God, explosions and mechanical or physical failures of equipment affecting QEP’s facilities or facilities of third parties. If the escalation of fees is insufficient to cover increased costs, if third parties do not renew or extend their contracts with QEP or if third parties suspend or terminate their contracts with QEP, the Company’s financial results would suffer.
 
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 production rates and 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 interest 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 ratio of indebtedness to Consolidated EBITDAX (as defined in the credit agreement.)
 
QEP relies on access to capital markets to meet long-term funding needs. 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 production, 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 of a majority of its production and major development projects, QEP pays joint venture expenses and in some cases 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 venture partner could result in financial losses. In addition, QEP’s commodity derivative transactions expose it to risk of financial loss if the counterparty fails to perform under a contract. During periods of falling commodity prices, QEP’s commodity derivative receivable positions increase, which increases its counterparty credit exposure.
 
 
QEP faces various risks associated with the trend toward increased activism against oil and gas exploration and development activities. Opposition toward oil and gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and gas industry, such as QEP, are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, environmental compliance and business practices. Anti-development activists are working to, amongst other things, reduce access to federal and state government lands and delay or cancel certain projects such as the development of oil or gas shale plays. For example, environmental activists have recently advocated for increased regulations on shale drilling in the U.S. Future activist efforts could result in the following:
 
 
delay or denial of drilling permits;
 
 
shortening of lease terms or reduction in lease size;
 
 
restrictions on installation or operation of gathering or processing facilities;
 
 
restrictions on the use of certain operating practices, such as hydraulic fracturing;
 
 
increased severance and/or other taxes;
 
 
legal challenges or lawsuits;
 
 
damaging publicity about QEP;
 
 
increased costs of doing business;
 
 
reduction in demand for QEP’s products; and
 
 
other adverse affects on QEP’s ability to develop its properties and expand production.
 
QEP’s need to incur costs associated with responding to these initiatives or complying with any resulting additional legal or regulatory requirements that are substantial and not adequately provided for could have a material adverse effect on its business, financial condition and results of operations.
 
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 exposure to the volatility of 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 enters into commodity derivative transactions, it may forgo some or all of the benefits of commodity price increases. Additionally, there are proposed financial regulations which may change QEP’s reporting and margining requirements relating to such instruments. Furthermore, QEP’s use of derivative instruments through which it attempts to reduce the economic risk of its participation in commodity markets could result in increased volatility of QEP’s reported results. Changes in the fair values (gains and losses) of derivatives that have not been designated as cash flow hedges must be recorded into QEP’s income. This creates the risk of volatility in earnings even if no economic impact to QEP has occurred during the applicable period.
 
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 our counterparties assessment of QEP’s credit risk.

Relative changes in NGL product and natural gas prices may adversely impact QEP’s results due to frac spread, natural gas and liquids exposure. Approximately 30% and 22% of QEP Field Services’ net operating revenues for 2011 and 2010, respectively, were derived from keep-whole processing agreements. Under QEP’s keep-whole arrangements, QEP’s principal cost is delivering dry gas of an equivalent Btu content to replace Btus extracted from the gas stream in the form of NGLs, or consumed as fuel during processing. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the "frac spread." Generally, the frac spread and, consequently, the net operating margins are positive under these contracts. In the event natural gas becomes more expensive on a Btu equivalent basis than NGL products, QEP’s cost of keeping the producer "whole" results in operating losses.  Due to timing of gas purchases and liquid sales, direct exposure to changes in market prices of either gas or liquids can be created, because there is an offsetting purchase or sale that remains exposed to market pricing. Through QEP’s marketing and derivatives activity, direct exposure may occur naturally or QEP may choose direct price exposure to either gas or liquids when QEP favors that exposure over frac spread risk. Given that QEP has derivative positions, adverse movement in prices to the positions QEP has taken will negatively impact results.
 
QEP has made significant investments in new cryogenic gas processing plants in its Northern Region (Rockies) in recent years. The expected returns on these investments depend in large part on the future price of ethane and ethane margins, which historically have been more volatile than the price of propane and butane. QEP competitors have also made significant investments in gas processing plants that recover significant volumes of ethane. The U.S. ethane market may, and probably will, become oversupplied from time to time in the future, resulting in lower ethane prices.

 
QEP’s plans to grow its midstream business by constructing new processing and treating facilities subjects the Company to construction risks and the risk that the Company will not be able to secure long-term contracts from third parties required to earn acceptable returns on these investments. One of the ways QEP has grown its business is through the construction of new gathering, treating and processing facilities. The construction of gathering, treating and processing facilities requires the expenditure of significant amounts of capital and involves numerous regulatory, environmental, political, legal and inflationary uncertainties. If QEP undertakes these projects, QEP may not be able to complete them on schedule, or at all, or at the budgeted cost. While QEP may commit natural gas supplies from its production, such supplies many not be sufficient to fill available capacity at these facilities, leaving QEP with limited natural gas supplies committed to these facilities prior to and after their construction. Moreover, QEP may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize.  QEP may also rely on estimates of proved reserves in its decision to construct new facilities, which may prove to be inaccurate, because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to process or treat enough natural gas to achieve QEP’s expected investment return, which could adversely affect QEP’s operations and cash flows.
 
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 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;
 
 
obtaining 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.
 
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 the Company’s controls and procedures to detect error or fraud could seriously harm its business and results of operations. QEP’s management, including its Chief Executive Officer and Chief Financial Officer, does not expect that the Company’s 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 QEP’s controls can provide absolute assurance that all control issues and instances of fraud, if any, in the 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, tribal, local and other laws and regulations that could adversely affect its cost of doing business and recording of proved reserves. QEP’s operations are subject to extensive regulation. The failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the Company’s operations increases its cost of doing business and, consequently, affects its profitability. Due to the myriad of complex federal, state, tribal and local regulations that may affect the Company, directly or indirectly, the following discussion of certain laws and regulations should not be considered an exhaustive review of all regulatory considerations affecting its operations.
 
The Company is subject to extensive federal, state, tribal 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 that could threaten QEP’s authorization to operate.
 
QEP must comply with numerous and complex federal and state regulations governing activities on federal, state and tribal lands, notably the National Environmental Policy Act, the Endangered Species Act, the Clean Air Act, the Clean Water Act, the Safe Drinking Water Act, the Oil Pollution Act, and the National Historic Preservation Act and similar state laws. 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.
 
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 stormwater, 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.
 
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 natural 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.
 
FERC regulates interstate natural gas transportation (including storage). 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. 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.
 
The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978.  These statutes are administered by FERC.  Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all "first sales" of natural gas, which includes all sales by QEP of its own production.  All other sales of natural gas by QEP, such as those of natural gas purchased from third parties, remain jurisdictional sales subject to a blanket sales certificate under the NGA, which has flexible terms and conditions.  Consequently, all of QEP’s sales of natural gas currently may be made at market prices, subject to applicable contract provisions.  QEP’s jurisdictional sales, however, are subject to the future possibility of greater federal oversight, including the possibility that the FERC might prospectively impose more restrictive conditions on such sales.  Conversely, sales of oil and condensate and NGL by QEP are made at unregulated market prices.
 
 
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.
 
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation. On September 12, 2011, President Obama sent a legislative package to Congress that included proposed legislation that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes included (i) the repeal of the percentage depletion allowance for oil and natural gas wells, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. President Obama’s Proposed Fiscal Year 2012 Budget includes the foregoing proposals in substantially similar form. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development and increase the cost of exploration and development of natural gas and oil resources. Any such changes could have an adverse effect on QEP’s financial position, results of operations and cash flows.
 
Federal and state hydraulic fracturing legislation or regulatory initiatives could increase QEP’s costs and restrict its access to natural gas and oil reserves. All wells drilled in tight sand and shale reservoirs require hydraulic fracture stimulation to achieve economic production rates and recoverable reserves. The majority of the Company’s current and future production and oil and gas reserves are 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 the 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 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 and reduces produced water disposal volumes. The Company believes that the employment of fracture stimulation technology does not present any significant additional risks other than the risks generally associated with natural gas and oil drilling and production operations described above, such as the risk of spills, releases, discharges, accidents and injuries to persons and property.
 
Currently, all well construction activities, including hydraulic fracture stimulation, are regulated by state agencies that review and approve all aspects of natural gas and oil well design and operation. The Company supports disclosure of the contents of hydraulic fracturing fluids, and submits information regarding its wells to the national online disclosure registry, FracFocus (www.fracfocus.org). The EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states have adopted and other states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. In the event that new or more stringent federal, state or local legal restrictions or moratoria are adopted in areas where QEP operates, QEP could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling or stimulating wells in some areas.
 
In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA recently announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a wastewater treatment plant. In addition, the U.S. Department of Energy is conducting an investigation of practices the agency could recommend to better protect the environment from drilling employing hydraulic fracture stimulation. Also, the U.S. Department of the Interior has indicated it intends to issue new regulations regarding disclosure requirements and other mandates for hydraulic fracturing on federal lands. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; the U.S. Securities & Exchange Commission to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.
 
 
QEP’s ability to produce natural gas and oil economically and in commercial quantities could be impaired if it is unable to acquire adequate supplies of water for its drilling operations or is unable to dispose of or recycle the water it uses at a reasonable cost and in accordance with applicable environmental rules. The hydraulic fracturing process on which QEP depends to produce commercial quantities of natural gas and oil requires the use and disposal of significant quantities of water. QEP’s inability to secure sufficient amounts of water, or to dispose of or recycle the water used in its operations, could adversely impact its operations in these regions. As noted above, the imposition of new environmental initiatives and regulations could include restrictions on QEP’s ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase QEP’s operating costs and cause delays, interruptions or termination of its operations, the extent of which cannot be predicted, and all of which could have an adverse effect on QEP’s operations and financial condition.
 
The adoption of greenhouse gas (GHG) 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 GHG emissions. QEP’s ability to access and develop new natural gas reserves may be restricted by climate-change regulation. In legislative sessions bills have been pending in Congress that would regulate GHG emissions through a cap-and-trade system under which emitters would be required to buy allowances for offsets of emissions of GHG. The Environmental Protection Agency (EPA) has adopted final regulations for the measurement and reporting of GHG emitted from certain large facilities (25,000 tons/year of carbon dioxide (CO2) equivalent) beginning with operations in 2010. The first such reports were filed with the EPA prior to March 31, 2011. Additionally, the EPA and authorized states have begun the permitting of major sources of GHG under the Clean Air Act pursuant to the EPA’s GHG Tailoring Rule whereby new and existing sources of GHG emitting above major source thresholds (100,000 metric tons per year of CO2  equivalent emissions) will be required to obtain major source permits. In addition, several of the states in which QEP operates are considering various GHG registration and reduction programs. Carbon dioxide and other GHG 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 at the federal level, 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 Northern and Southern 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 anthropogenic emissions of GHG. Management does not, however, 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 exempts non-financial end-users using derivatives to hedge business risk from the central clearing requirements of the Dodd-Frank Act. The availability of the “end-user exemption” to exempt commercial end-users from the act’s margin requirements depends on rules not yet finalized by the Commodities Futures and Trading Commission (CFTC). In January 2012, the CFTC released an updated timeline indicating that the CFTC would finalize these rules in the first quarter of 2012.
 
If an end-user exemption from the Dodd-Frank Act’s margin requirements is not available to QEP, the Company could be required to post significant amounts of cash collateral with its dealer counterparties for its 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 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, increase the volatility of QEP’s results of operations and reduce the predictability of the Company’s cash flows, which in turn could adversely affect QEP’s ability to plan for and fund capital expenditures.
 
 
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 Company’s pension plans are currently underfunded and may require large contributions, which may divert funds from other uses. Approximately 190 of QEP’s employees participate in the closed defined benefit pension plan (QEP Resources, Inc. Retirement Plan). Over time, periods of declines in interest rates and pension asset values may result in a reduction in the funded status of the Company’s pension plans. As of December 31, 2011 and 2010, QEP’s pension plans were $59.9 million and $47.1 million underfunded. The underfunded status of QEP’s pension plans may require that the Company make large contributions to such plans. QEP made cash contributions of $14.8 million and $1.6 million in 2011 and 2010, respectively, to its defined benefit pension plans and expect to make contributions of approximately $6.3 million to the funded plan in 2012. QEP cannot, however, predict whether changing economic conditions, the future performance of assets in the plans or other factors will require the Company to make contributions in excess of its current expectations, diverting funds QEP would otherwise apply to other uses.
 
ITEM 1B. UNRESOLVED STAFF COMMENTS
 
None
 
ITEM 2. PROPERTIES
 
EXPLORATION AND PRODUCTION
 
QEP’s exploration and production business is conducted through QEP Energy in two core regions – the Northern Region (including the states of Wyoming, Utah, Colorado, New Mexico and North Dakota) and the Southern Region (including the states of Oklahoma, Texas and Louisiana).
 
Southern Region
 
Haynesville/Cotton Valley
 
QEP Energy has approximately 50,800 net acres of Haynesville Shale lease rights in northwest Louisiana and additional lease rights that cover the Hosston and Cotton Valley formations. The depth of the top of the Haynesville Shale ranges from approximately 10,500 feet to 12,500 feet across QEP Energy’s leasehold and is below the Hosston and Cotton Valley formations that QEP Energy has been developing in northwest Louisiana for over a decade. As of December 31, 2011, QEP Energy had three operated rigs drilling in the project area.
 
Midcontinent
 
QEP Energy’s Midcontinent properties cover all properties in the Southern Region except the Haynesville/Cotton Valley area of northwest Louisiana and are distributed over a large area, including the Anadarko Basin of Oklahoma and the Texas Panhandle.
 
QEP Energy has approximately 77,000 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. As of December 31, 2011, QEP Energy had two operated rigs drilling in the project.
 
QEP Energy has approximately 38,700 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. 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. In the past few years, QEP and other operators have drilled a number of successful horizontal wells in the Granite Wash/Atoka Wash play but have also drilled some wells with disappointing results. As of December 31, 2011, QEP Energy did not have any rigs drilling in the Granite Wash/Atoka Wash. In addition to its operated drilling programs, QEP Energy receives and participates in a large number of outside-operated well proposals.
 
 
Northern Region
 
Pinedale Anticline
 
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. The Company currently estimates that up to 1,100 additional wells will be required to fully develop its Pinedale acreage on a combination of 5 and 10-acre density. In addition to QEP Energy’s gross producing wells, QEP Energy had an overriding royalty interest only in an additional 21 wells at Pinedale.
 
Uinta Basin
 
The majority of 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 255,200 net leasehold acres in the Uinta Basin.
 
Rockies Legacy
 
The remainder of QEP Energy Northern Region leasehold interests, productive wells and proved reserves are distributed over a number of fields and properties managed as the Rockies Legacy division. Exploration and development activity in 2011 includes wells in the Powder River and Greater Green River Basins in Wyoming and the Williston Basin in North Dakota.
 
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. As of December 31, 2011, QEP Energy had one operated rig drilling in the project area.
 
Reserves – QEP Energy
 
At December 31, 2011 and 2010, approximately 91% and 88% of QEP Energy’s estimated proved reserves were Company operated. Proved developed reserves represented 54% and 53% of the Company’s total proved reserves at December 31, 2011 and 2010, respectively, while the remaining 46% and 47% of reserves were classified as proved undeveloped at December 31, 2011 and 2010. 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, 2011
   
December 31, 2010
 
   
Natural
 Gas
   
Oil
   
NGL
   
Natural Gas
Equivalents (1)
   
Natural
Gas
   
Oil
   
NGL
   
Natural Gas
Equivalents (1)
 
   
(Bcf)
   
(Mbbl)
   
(Mbbl)
     (Bcfe)    
(Bcf)
   
(Mbbl)
   
(Mbbl)
     (Bcfe)  
Proved developed reserves
    1,538.3       32,955.5       38,388.1       1,966.3       1,404.8       25,115.6       9,342.9       1,611.5  
Proved undeveloped reserves
    1,211.1       34,559.3       38,169.0       1,647.5       1,208.1       27,161.1       8,026.6       1,419.2  
Total proved reserves
    2,749.4       67,514.8       76,557.1       3,613.8       2,612.9       52,276.7       17,369.5       3,030.7  
 

(1)
Oil and NGLs are converted to natural gas equivalents at the ratio of one bbl of oil or NGL to six Mcf of equivalent natural gas.
 
QEP Energy’s reserve statistics for the years ended December 31, 2009 through 2011, are summarized below:
 
Year ended
December 31,
 
Year End
Resrves (Bcfe)
   
Natural Gas, Oil
and NGL
 Production (Bcfe)
   
Reseve Life
Index (1)
(Years)
 
       
2009
    2,746.9       189.5       14.5  
2010
    3,030.7       229.0       13.2  
2011
    3,613.8       275.2       13.1  
 

(1)
Reserve life index is calculated by dividing year-end proved reserves by production for such year.
 
 
Proved Reserves
 
Reserve and related information for 2011 and 2010 is presented consistent with the requirements of the SEC’s rules for the Modernization of Oil and Gas Reporting, that we adopted December 31, 2009. These revised rules expand the use of reliable technologies to estimate and categorize reserves and require the use of the average of the first-of-the-month prices for the prior 12 months (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 14 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.
 
QEP Energy’s proved reserves in major operating areas at December 31, 2011 and 2010 are summarized below:
 
   
2011
   
2010
 
   
(Bcfe)
   
(% of total)
   
(Bcfe)
   
(% of total)
 
Southern Region
                       
Haynesville/Cotton Valley
    782.9       22       728.3       24  
Midcontinent
    518.7       14       442.2       15  
Northern Region
                               
Pinedale Anticline
    1,531.0       42       1,348.9       44  
Uinta Basin
    393.6       11       212.8       7  
Rockies Legacy
    387.6       11       298.5       10  
Total QEP Energy
    3,613.8       100       3,030.7       100  
 
Estimates of the quantity of proved reserves from the Company’s Pinedale Anticline leasehold in western Wyoming have changed substantially over time as a result of numerous factors including, but not limited to, additional development drilling activity, producing well performance and the development and application of reliable technologies. The continued analysis of new data has led to progressive increases in estimates of original gas-in-place at Pinedale and to a better understanding of the appropriate well density to maximize the economic recovery of the in-place volumes. With the application of the amendments of ASC 932 in ASU 2010-03, reserves associated with Pinedale increased density drilling are included in extensions and discoveries for the years ended December 31, 2011, 2010 and 2009, because each new well drilled recovers incremental reserves that would otherwise be unrecoverable.
 
Proved Undeveloped Reserves
 
Significant changes to proved undeveloped reserves (PUDs) occurring during 2011 are summarized in the table below:
 
   
2011
 
   
(Bcfe)
 
Proved undeveloped reserves at January 1,
    1,419.2  
Transferred to proved developed reserves
    (314.5 )
Revisions to previous estimates
    (37.2 )
Extensions and discoveries
    580.0  
Proved undeveloped reserves at December 31, (1)
    1,647.5  
 

(1)
All of QEP Energy’s proved undeveloped reserves at December 31, 2011, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves, except for 217 Bcfe located within the northern portion of the Company’s Pinedale Anticline leasehold in western Wyoming. Long-term development of natural gas reserves in Pinedale is governed by the BLM’s September 2008, ROD on the FSEIS. Under the ROD, QEP Energy is allowed to drill and complete wells year-round in designated concentrated development areas. The ROD contains additional requirements and restrictions on the sequence of development, which requires the Company to develop its leasehold from the south to the north. These restrictions result in protracted, phased development that is beyond the control of the Company. The Company has an ongoing development plan and the financial capability to continue development in the manner estimated.

The costs incurred to continue the development of proved undeveloped reserves were approximately $533.6 million, $434.2 million and $216.1 million for the years ended December 31 2011, 2010 and 2009, respectively. The costs incurred in 2011 related to the drilling of PUDs in QEP development projects, which are discussed in Item 2 above. This investment resulted in the transfer in 2011 of 314.5 Bcfe of reserves from proved undeveloped to proved developed, representing 22% of the total proved undeveloped reserves that were recorded at December 31, 2010.
 
Estimated future development costs relating to the development of PUDs are projected to be approximately $614.9 million in 2012, $788.8 million in 2013 and $757.7 million in 2014. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. Proved undeveloped reserves related to major development projects will be reclassified to proved developed reserves when production commences.
 
 
Internal Controls Over Reserve Estimates, Technical Qualifications and Technologies Used
 
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-functional reserves review committee responsible to the Company’s board of directors. We retained Ryder Scott Company, independent oil and gas reserve evaluation engineering consultants (“Ryder Scott”), to prepare the estimates of 100% of our reserves as of December 31, 2011, 2010 and 2009. The individual at Ryder Scott who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2011, is a registered Professional Engineer in the State of Colorado and graduated with a Bachelors of Science degree in Geology from the University of Missouri at Rolla in 1976. The individual has over thirty years experience in the Petroleum Industry, including experience estimating and evaluating petroleum reserves. A more detailed letter of the individual’s professional qualifications has been filed as part of Exhibit 23.2 to this report.
 
The individual at QEP Resources responsible for insuring the accuracy of the reserve estimate preparation material provided to Ryder Scott and reviewing the estimates of reserves received from Ryder Scott was our Chief Reservoir Engineer. Such individual is a member of the Society of Petroleum Engineers and graduated with a Bachelors of Science degree in Petroleum Engineering from Mississippi State University in 1993. This individual has 17 years experience in the Petroleum Industry, including 13 years reservoir engineering experience in most of the active domestic basins in the United States. A more detailed letter of the individual’s professional qualifications has been filed as part of Exhibit 23.2 to this report.
 
The SEC’s new rules expanded the technologies that a company can use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. A variety of methodologies were used to determine our proved reserve estimates. The principal methodologies employed are performance, analogy or volumetric methods. All of the proved producing reserves attributable to producing wells and reservoirs were estimated by performance methods. Performance methods include, but may not be limited to, decline curve analysis which utilizes extrapolations of historical production and pressure data. Approximately 99 percent of QEP’s proved developed non-producing and undeveloped reserves included in this Annual Report on Form 10-K were estimated by analogy and the remaining approximately one percent of the proved developed non-producing and undeveloped reserves were estimated by the volumetric method. Some combination of these methods is used to determine reserve estimates in substantially all of QEP’s fields.
 
Refer to Note 14 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, 2011, with the Energy Information Administration of the Department of Energy on Form EIA-23. Although QEP uses the same technical and economic assumptions when it prepares the EIA-23 as used to estimate reserves for this Annual Report on Form 10-K, it is obligated to report reserves for only wells it operates, not for all of the wells in which it has an interest, and to include the reserves attributable to other owners in such wells.
 
Production, Production Prices and Production Costs
 
The following table sets forth the net production volumes, the average net realized prices per Mcf of natural gas, per bbl of oil and per bbl of NGL produced, and the operating expenses per Mcfe for the years ended December 31, 2011, 2010 and 2009.
 
   
Year Ended December 31,
 
   
2011
   
2010
   
2009
 
QEP Energy
     
Volumes produced and sold
                 
Natural gas (Bcf)
    236.4       203.8       168.7  
Oil (Mbbl)
    3,741.3       2,979.8       2,746.7  
NGL (Mbbl)
    2,715.6       1,225.8       705.0  
Total production (Bcfe)
    275.2       229.0       189.5  
Average field-level price (1) (2)
                       
Natural gas (per Mcf)
  $ 3.95     $ 4.18     $ 3.48  
Oil (per bbl)
    86.20       69.39       50.88  
NGL (per bbl)
    47.76       39.04       31.82  
Lifting costs (per Mcfe)
                       
Lease operating expense
  $ 0.54     $ 0.56     $ 0.67  
Production taxes
    0.36       0.34       0.31  
Total lifting costs
  $ 0.90     $ 0.90     $ 0.98  
 

(1)
During the year ended December 31, 2011, QEP revised its reporting of transportation and handling costs. Transportation and handling costs, previously netted against revenues, were recast on the Consolidated Income Statement from revenues to “Natural gas, oil and NGL transportation and other handling costs” for all periods presented. This change had no impact on net income. See Note 1 “Summary of Significant Accounting Policies,” in Item 8, Part II of this Annual Report on Form 10-K, for additional information.
(2)
The average field-level price does not include the impact of settled commodity price derivatives.
 
 
A summary of natural gas production by major geographical area is shown in the following table:
 
   
For the year ended December 31,
   
Change
 
   
2011
   
2010
   
2009
   
2011 vs. 2010
   
2010 vs. 2009
 
QEP Energy - Natural gas (Bcf)
                             
Southern Region
                             
Haynesville/Cotton Valley
    107.1       79.3       46.9       27.8       32.4  
Midcontinent
    32.9       30.8       32.7       2.1       (1.9 )
Northern Region
                                       
Pinedale Anticline
    69.3       65.1       58.9       4.2       6.2  
Uinta Basin
    14.9       14.9       16.7       -       (1.8 )
Rockies Legacy
    12.2       13.7       13.5       (1.5 )     0.2  
Total production
    236.4       203.8       168.7       32.6       35.1  
 
A summary of oil production by major geographical area is shown in the following table:
 
   
For the year ended December 31,
   
Change
 
   
2011
   
2010
   
2009
   
2011 vs. 2010
   
2010 vs. 2009
 
QEP Energy - Oil (Mbbl)
                             
Southern Region
                             
Haynesville/Cotton Valley
    51.0       78.4       121.1       (27.4 )     (42.7 )
Midcontinent
    835.3       644.3       775.1       191.0       (130.8 )
Northern Region
                                       
Pinedale Anticline
    583.8       551.8       486.9       32.0       64.9  
Uinta Basin
    866.7       957.1       930.7       (90.4 )     26.4  
Rockies Legacy
    1,404.5       748.2       432.9       656.3       315.3  
Total production
    3,741.3       2,979.8       2,746.7       761.5       233.1  
 
 
A summary of NGL production by major geographical area is shown in the following table:
 
   
For the year ended December 31,
   
Change
 
   
2011
   
2010
   
2009
   
2011 vs. 2010
   
2010 vs. 2009
 
QEP Energy - NGL (Mbbl)
                             
Southern Region
                             
Haynesville/Cotton Valley
    8.4       5.5       3.3       2.9       2.2  
Midcontinent
    1,371.2       997.0       456.1       374.2       540.9  
Northern Region
                                       
Pinedale Anticline
    1,099.6       -       -       1,099.6       -  
Uinta Basin
    106.4       121.5       151.2       (15.1 )     (29.7 )
Rockies Legacy
    130.0       101.8       94.4       28.2       7.4  
Total production
    2,715.6       1,225.8       705.0       1,489.8       520.8  
 
A summary of natural gas equivalent total production by major geographical area is shown in the following table:
 
   
For the year ended December 31,
   
Change
 
   
2011
   
2010
   
2009
   
2011 vs. 2010
   
2010 vs. 2009
 
QEP Energy - Total Production (Bcfe)
                             
Southern Region
                             
Haynesville/Cotton Valley
    107.5       79.8       47.7       27.7       32.1  
Midcontinent
    46.2       40.6       40.1       5.6       0.5  
Northern Region
                                       
Pinedale Anticline
    79.4       68.5       61.8       10.9       6.7  
Uinta Basin
    20.8       21.4       23.2       (0.6 )     (1.8 )
Rockies Legacy
    21.3       18.7       16.7       2.6       2.0  
Total production
    275.2       229.0       189.5       46.2       39.5  
 
Productive Wells
 
The following table summarizes the Company’s productive wells as of December 31, 2011. All of our wells are located in the United States.
 
   
Natural gas
   
Oil
   
Total
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Southern Region
                                   
Haynesville/Cotton Valley
    1,413       669       7       4       1,420       673  
Midcontinent
    1,757       544       378       84       2,135       628  
Northern Region
                                               
Pinedale Anticline
    613       377       -       -       613       377  
Uinta Basin
    660       469       1,651       194       2,311       663  
Rockies Legacy
    780       272       431       161       1,211       433  
Total productive wells
    5,223       2,331       2,467       443       7,690       2,774  
 
The term “gross” refers to all wells or acreage in which QEP has at least a partial working interest and the term “net” refers to QEP’s ownership represented by that working interest. Although many wells produce both natural gas and oil, and many natural gas wells also have allocated NGL volumes from processing, a well is categorized as either a natural gas or an oil well based upon the ratio of gas to oil produced at the wellhead. Each gross well completed in more than one producing zone is counted as a single well. At the end of 2011, the Company had 90 gross wells with completions in more than one reservoir.
 
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.
 
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, 2011. “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
    33,733       9,837       5,369       3,362       39,102       13,199  
Colorado
    155,897       105,737       111,062       33,389       266,959       139,126  
Kansas
    28,994       12,894       52,379       17,205       81,373       30,099  
Louisiana
    72,351       60,036       6,483       6,064       78,834       66,100  
Montana
    14,294       7,637       306,619       52,843       320,913       60,480  
New Mexico
    99,802       71,859       32,619       12,600       132,421       84,459  
North Dakota
    38,033       10,804       212,652       88,756       250,685       99,560  
Oklahoma
    655,124       275,690       489,406       150,279       1,144,530       425,969  
South Dakota
    -       -       204,398       107,151       204,398       107,151  
Texas
    133,602       46,593       51,927       49,206       185,529       95,799  
Utah
    167,052       134,208       235,542       152,897       402,594       287,105  
Wyoming
    265,196       158,043       388,755       276,866       653,951       434,909  
Other
    2,429       735       158,475       43,357       160,904       44,092  
Total
    1,666,507       894,073       2,255,686       993,975       3,922,193       1,888,048  
 

(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,
           
2012
    56,351       36,718  
2013
    130,548       73,981  
2014
    67,140       47,618  
2015
    92,182       73,661  
2016 and later
    152,370       145,321  
 
 
Drilling Activity
 
The following table summarizes the number of development and exploratory wells drilled on acreage owned by QEP during the years indicated.
 
   
Developmental Wells
   
Exploratory Wells
 
   
Productive
   
Dry
   
Productive
   
Dry
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Year Ended December 31, 2011
                                               
Southern Region
                                               
Haynesville/Cotton Valley
    91.0       36.7       -       -       6.0       1.7       2.0       0.7  
Midcontinent
    221.0       39.6       -       -       -       -       4.0       1.9  
Northern Region
                                                               
Pinedale
    105.0       71.6       -       -       -       -       -       -  
Uinta Basin
    176.0       6.3       -       -       -       -       -       -  
Rockies Legacy
    85.0       22.5       -       -       -       -       -       -  
Total
    678.0       176.7       -       -       6.0       1.7       6.0       2.6  
Year Ended December 31, 2010
                                                               
Southern Region
                                                               
Haynesville/Cotton Valley
    85.0       44.0       -       -       33.0       16.2       1.0       1.0  
Midcontinent
    98.0       22.4       -       -       -       -       -       -  
Northern Region
                                                               
Pinedale
    103.0       72.5       -       -       -       -       -       -  
Uinta Basin
    188.0       23.9       -       -       -       -       -       -  
Rockies Legacy
    42.0       7.7       -       -       -       -       1.0       0.9  
Total
    516.0       170.5       -       -       33.0       16.2       2.0       1.9  
Year Ended December 31, 2009
                                                               
Southern Region
                                                               
Haynesville/Cotton Valley
    82.0       61.6       -       -       8.0       1.8       -       -  
Midcontinent
    76.0       24.8       -       -       -       -       -       -  
Northern Region
                                                               
Pinedale
    96.0       58.6       -       -       -       -       -       -  
Uinta Basin
    7.0       6.7       -       -       -       -       -       -  
Rockies Legacy
    12.0       2.8       1.0       -       4.0       1.9       -       -  
Total
    273.0       154.5       1.0       -       12.0       3.7       -       -  
 
The following table presents operated and non-operated well activity at December 31, 2011 as well as completions for the year ended December 31, 2011:
 
   
Operated
   
Non-operated
 
   
Completions
   
Drilling
   
Waiting on completion
   
Completions
   
Drilling
   
Waiting on completion
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Southern Region
                                                                       
Haynesville/Cotton Valley
    38.0       30.3       8.0       6.9       21.0       10.6       59.0       8.1       -       -       4.0       0.3  
Midcontinent
    29.0       21.8       2.0       1.3       4.0       2.4       192.0       17.8       13.0       1.7       11.0       2.1  
Northern Region
                                                                                               
Pinedale
    105.0       71.6       4.0       2.4       24.0       17.3       -       -       -       -       -       -  
Uinta Basin
    7.0       5.9       1.0       1.0       2.0       2.0       169.0       0.4       2.0       0.1       -       -  
Rockies Legacy
    23.0       20.1       -       -       4.0       3.7       62.0       2.4       13.0       0.4       20.0       4.2  
 
Delivery Commitments
 
The Company sells NGLs under a term sales agreement that contains a delivery commitment for 8,500 barrels per day of NGL derived from several of QEP Field Services’ gas processing facilities in the Northern Region. The agreement, which was effective May 1, 2010, extends for a period of seven years and contains terms and conditions customary for an agreement of this type in the oil and gas industry. The Company believes that the reserves dedicated to its gas processing facilities and projected processing volumes are adequate to satisfy its delivery commitments under this agreement.
 
 
The Company is a party to various long-term sales commitments for physical delivery of natural gas with future firm delivery commitments as follows:
 
   
Delivery Commitments
 
Period
 
(millions of MMBtu)
 
2012
    186.7  
2013
    75.8  
2014
    28.9  
2015
    18.8  
2016
    -  
After 2016
    -  
 
These commitments are physical delivery obligations with prices related to the prevailing index prices for natural gas at the time of delivery. None of these commitments require the Company to deliver natural gas produced specifically from any of the Company’s properties. The Company believes that its production and reserves are adequate to meet these term sales commitments. If for some reason the Company’s natural gas production is not sufficient to satisfy its term sales commitments, the Company believes it can purchase sufficient volumes of natural gas in the market at index-related prices to satisfy its commitments.
 
In addition, none of the Company’s production from QEP Energy owned properties is subject to any priorities, proration or third-party imposed curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies, or any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in “Risk Factors” in this Annual Report on Form 10-K.
 
MIDSTREAM FIELD SERVICES – QEP Field Services
 
QEP Field Services owns 1,905 miles of gathering lines in Utah, Wyoming, Colorado, Louisiana and North Dakota. At December 31, 2011 QEP Field Services also owns processing plants, which remove NGL from the natural gas stream, that have an aggregate processing capacity, of 1.37 Bcf 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 600 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 300 miles of gathering lines and associated field equipment, the UBFS system, which consists of 78 miles of gathering lines and associated field equipment and the Three Rivers system, which consists of 52 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, an expansion of its Stagecoach processing complex in the Uinta Basin of eastern Utah. The plant predominantly provides fee-based processing services to third parties. In July 2011, QEP Field Services commissioned the 420 MMcf per day Blacks Fork II cryogenic processing plant, an expansion of its Blacks Fork processing complex located in the Green River Basin of southwestern Wyoming. The Blacks Fork complex is about 100 miles south of QEP’s operations at Pinedale. QEP expects that the Blacks Fork II plant at full capacity will be able to extract an incremental net 16,000 bbls per day of NGL.
 
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 approximately 8 Bcf, comprised of an inventory of approximately 4 Bcf of QEP Marketing-owned cushion gas and working gas storage capacity of about 4 Bcf.
 
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. Individual members of the Ute Indian Tribe’s Business Committee intervened as co-plaintiffs asserting the same CAA claims as the federal government. 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 and operated by QEP Field Services. 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 monitoring, testing and reporting, among other requirements. QEP Field Services contends that its facilities have pollution controls installed, as part of their operational design, 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 against EPA’s claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying 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.
 
 
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 denied that the drilling and operation of the 14P well and associated equipment violated any provisions of the CAA. QEP and EPA entered into an administrative order on consent, effective June 17, 2011, resolving all disputes associated with prospective CAA compliance at the Flat Rock 14P well. Among other matters, the order requires installation of pollution control equipment to destroy vapors from the well’s dehydration equipment and ongoing monitoring and reporting associated with operation of that control equipment.
 
ITEM 4. MINE SAFETY DISCLOSURES
 
Not applicable.
 
 
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 January 31, 2012, QEP had 7,793 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. The Company expects that cash dividends will continue to be paid in the future. 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)
 
2011
                 
First quarter
  $ 42.00     $ 35.78     $ 0.02  
Second quarter
    43.70       37.11       0.02  
Third quarter
    45.20       26.52       0.02  
Fourth quarter
    38.44       23.56       0.02  
                    $ 0.08  
                         
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 stock 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 stock, the S&P 500 Index and the Company’s peer group as of July 1, 2010, which is the date when QEP’s common stock began trading on the NYSE;
 
 
Investment in the Company’s peer group was weighted based on the stock market capitalization of each individual company within the peer group at the beginning of each period for which a return is indicated; and
 
 
Dividends were reinvested on the relevant payment dates.
 
 
QEP’s 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., Pioneer Natural Resources Company, Plains Exploration & Production Company, Quicksilver Resources, Inc., Range Resources Corporation, Southwestern Energy Company, Ultra Petroleum Corporation and Whiting Petroleum Corporation. Petrohawk Energy Corporation was removed from the peer group in 2011, due to its acquisition by BHP Billington. Management believes this peer group provides a meaningful comparison based upon the Company’s review of asset size, geographic location of assets, market capitalization, revenues, culture and performance, among other things.
 
 
 
Purchases of equity securities by the issuer and affiliated purchasers
 
The following repurchases of QEP shares were made by an affiliated purchaser, QEP Resources Education Foundation, during the fourth quarter of 2011:
 
Period
 
Total number
of shares
purchased (1)
   
Weighted-
average price
paid per share
   
Total number of shares
purchased as part of
publicly announced
 plans or programs
   
Maximum number of
shares that may yet be
epurchased under the
plans or programs
 
October 1, 2011 - October 31, 2011
    -     $ -       -       -  
November 1, 2011 - November 30, 2011
    7,475     $ 37.3425       -       -  
December 1, 2011 - December 31, 2011
    -     $ -       -       -  
      7,475     $ 37.3425       -       -  
 
(1) QEP Resources Education Foundation, an affiliated purchaser, purchased the shares in open-market transactions.  These purchases were not made pursuant to a publicly announced plan or program.
 
 
ITEM 6. SELECTED FINANCIAL DATA
 
Selected financial data for the five years ended December 31, 2011, 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,
 
   
2011
   
2010
   
2009
   
2008
   
2007
 
   
(in millions)
 
Results of Operations (1)
                             
Revenues (2)
  $ 3,159.2     $ 2,300.6     $ 2,011.2     $ 2,360.9     $ 1,713.7  
Operating income
    505.9       545.3       585.5       933.2