10-K 1 qep-20121231x10k.htm 10-K QEP-2012.12.31-10K


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
 
ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
 
001-34778
 
 
(Commission File No.)
 

QEP RESOURCES, INC.
(Exact name of registrant as specified in its charter)
 
STATE OF DELAWARE
 
87-0287750
(State or other jurisdiction of incorporation)
 
(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  ý    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  ý
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  ý    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  ý    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.  ý
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
ý
 
Accelerated filer
o
 
 
 
 
 
Non-accelerated filer
o
(Do not check if a smaller reporting company)
Smaller reporting company
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý




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, 2012): $5,327,744,063.
 
At January 31, 2013, there were 178,551,744 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 2013 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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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Where You Can Find More Information
 
QEP Resources, Inc. (QEP or the Company) files annual, quarterly, and current reports with the Securities and Exchange Commission (SEC). Prior to QEP's Spin-off from Questar Corporation (described in more detail in 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 on Form 10-K 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;
natural gas, oil and NGL prices and factors affecting the volatility of such prices;
plans to drill or participate in wells and to defer completion of wells;
results from planned drilling operations and production operations;
amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
plans to divest of assets, including plans to separate portions of gathering assets into a master limited     partnership;
estimated reserves;
estimated accruals for loss contingencies and other items;
impact of lower commodity prices;
effect of recession;
plans to enter into derivative contracts for a portion of forecasted production;
future expenses and operating costs;
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;
the amount and timing of the settlement of derivative contracts;
incurrence of unrealized derivative gains and losses;
the ability of QEP to use derivative instruments to manage commodity price risk and the availability to the Company of the end-user exemption under Title VII of the Dodd-Frank Act;
impact of nonperformance by trade creditors or joint venture partners;

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the outcome of contingencies such as legal proceedings;
impact on earnings from discontinuing hedge accounting;
expected contributions to the Company's pension plans;
impact of recently issued accounting pronouncements;
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 in the market to cover any shortfalls;
conversion of proved undeveloped reserves to proved developed reserves;
the significance of Adjusted EBITDA as a measure of cash flow and liquidity;
payment of dividends;
potential for future asset impairments;
estimated future purchase accounting adjustments;
maintaining an appropriate debt rating; and
future activist efforts.


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 on Form 10-K;
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;
lack of available pipeline capacity;
QEP's inability to successfully integrate acquired assets or dispose of non-core assets;
the outcome of contingencies such as legal proceedings;
permitting delays;
operating risks such as unexpected drilling conditions;
weather conditions;
changes in maintenance and construction costs, including possible inflationary pressures;
the availability and cost of debt and equity financing;
changes in laws or regulations, including the implementation of the Dodd-Frank Act;
climate change and other initiatives related to drilling and completion techniques, including hydraulic fracturing;
derivative activities;
substantial liabilities from legal proceedings and environmental claims;
failure of internal controls and procedures;
elimination of federal income tax deductions for oil and gas exploration and development costs;
future opportunities that QEP's board of directors may determine present greater potential value to stockholders than planned divestiture of assets;
regulatory approvals and compliance with contractual obligations;
failure to obtain court approval or class member acceptances of settlement agreement for the Company's class action lawsuit;
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 on Form 10-K, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.



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Glossary of Terms

Adjusted EBITDA Adjusted EBITDA is a non-GAAP financial measure. Management defines Adjusted EBITDA as net income before the following items: separation costs, accrued litigation loss contingency, depreciation, depletion and amortization, exploration expense, abandonment and impairment, gains and losses from asset sales, unrealized gains and losses on derivative contracts, interest and other income, loss on early extinguishment of debt, interest expense, income taxes and discontinued operations.
 
B  Billion.
 
bbl  Barrel, which is equal to 42 U.S. gallons liquid volume 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.
 
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.

cryogenic processing  Utilizes refrigeration by reducing gas pressure across a turbo expander that reduces the gas temperature to 100 degrees below zero Fahrenheit.

cushion gas  Volume of gas that must remain in a natural gas 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 within the proved area of an oil or gas reservoir to the depth of a horizon known to be productive.

dry hole  A well drilled 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  An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

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 crude oil wells or "gross" acres are the total number of wells or acres in which the Company has a working interest.
 
IFNPCR   Inside the Federal Energy Regulatory Commission (FERC) monthly settlement index for the Northwest Pipeline Corporation Rocky Mountains.
 

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IFPEPL  Inside FERC monthly settlement index for the Panhandle Eastern Pipeline Company.
 
keep-whole processing Processing contracts where the Company retains and sells NGL extracted at its processing plants and keeps the customer "whole" by buying and delivering a Btu-equivalent amount of natural gas to the customer.

LIBOR London Interbank Offered Rate (LIBOR) is the interest rate that banks charge each other for one-month, three-month, six-month and one-year loans.

M  Thousand.
 
MM  Million.
 
Midstream  Gas gathering, compression, treating, processing, and transmission assets and activities that are non-jurisdictional. Also includes certain crude 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.

possible reserves Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

probable reserves Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
 
proved properties Properties with proved reserves.

proved reserves  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and 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, crude 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.

resource play Refers to regionally distributed oil and natural gas accumulation as opposed to conventional plays which are more limited in their area extent. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations in tight sand, shale and coal 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.
 

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seismic data  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, subject to all royalties, other burdens and to all capital costs and operating expenses.



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FORM 10-K
ANNUAL REPORT 2012
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: natural gas and crude oil exploration and production; midstream field services; and energy marketing. These businesses are conducted through the Company's three principal subsidiaries:
 
QEP Energy Company (QEP Energy) acquires, explores for, develops and produces natural gas, crude 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 crude oil, and owns and operates an underground natural gas storage reservoir.

QEP operates in the Northern and Southern Regions of the United States and is headquartered in Denver, Colorado. Principal offices are located in Denver, Colorado; Salt Lake City, Utah; and Tulsa, Oklahoma.
 
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 Annual Report on 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 13 - Discontinued Operations, to the consolidated financial statements in Item 8 of Part II this Annual Report on Form 10-K.

Financial and Operating Highlights

Our financial and operating highlights for 2012 include:

Generated net income of $128.3 million, or $0.72 per diluted share, a decrease of 52%, due primarily to the accrual of a litigation loss contingency of $115.0 million;
Generated Adjusted EBITDA (a non-GAAP financial measure defined and reconciled in Item 7 of Part II of this Annual Report on Form 10-K) of $1,415.5 million, up from $1,386.6 million in 2011;
Increased total production by 16% to 319.2 Bcfe and liquids (oil and NGL) production by 80% to 69.9 Bcfe;
Increased total proved reserves 9% to 3.9 Tcfe and increased liquid (oil and NGL) proved reserves by 52% to 1.3 Tcfe;
Added 572.5 Bcfe of proved reserves from extensions and discoveries;
Acquired $1.4 billion of assets in QEP's existing core acreage in the Williston Basin, North Dakota;
Increased Field Services gathering throughput volumes, NGL sales volumes and fee-based processing volumes by 2%, 3% and 4%, respectively; and

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Issued $1.15 billion of senior notes and entered into a $300 million five-year term loan.

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 those projects that generate optimal returns;
acquire businesses and assets that complement or expand our current business;
maintain a sustainable, diverse inventory of low cost, high-margin resource plays;
be in the highest-potential areas of the resource plays in which we operate;
build contiguous acreage positions that drive operating efficiencies;
be the operator of our assets, whenever possible;
be the low-cost driller and producer in each area where we operate;
own a controlling interest in and operate midstream infrastructure in our core producing areas to capture value downstream of the wellhead;
build gas processing plants to extract liquids from our natural gas streams;
gather, compress and treat our production to drive down costs;
support the growth of our midstream business with the intention of forming a Master Limited Partnership;
actively market our QEP Energy production to maximize value;
utilize derivative contracts to mitigate the impact of natural gas, crude oil or NGL price volatility, while locking in acceptable cash flows required to support future capital expenditures;
attract and retain the best people; and
maintain a capital structure that allows us the necessary financial flexibility with which to invest in organic growth and potential acquisition opportunities, as they may arise.

Exploration and Production – QEP Energy Company
 
QEP Energy is actively involved in several of North America's most important hydrocarbon resource plays. QEP Energy has a large inventory of identified development drilling locations, primarily on the Pinedale Anticline in western Wyoming; the Williston Basin in North Dakota; the Haynesville/Cotton Valley in northwestern Louisiana; the Uinta Basin in eastern Utah; Anadarko Basin in Oklahoma and Texas and other proven properties in Wyoming, Colorado and Utah. For 2013, QEP plans to allocate approximately 91% 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 as of December 31, 2012:

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QEP's exploration and production activities are conducted through QEP Energy, which generated approximately 80%, 76%, and 81% of the Company's Adjusted EBITDA (refer to Item 7 of Part II of this Annual Report on Form 10-K for management's definition and a reconciliation to net income of this non-GAAP financial measure) during the years ended December 31, 2012, 2011 and 2010, 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 Northern Region contributed 49% of 2012 production while the Southern Region contributed 51%. QEP Energy reported 3,936 Bcfe of estimated proved reserves as of December 31, 2012, up from 3,614 Bcfe at the end of 2011. Of those estimated proved reserves, approximately 74%, or 2,876 Bcfe, were located in the Northern Region at December 31, 2012, compared to 64% or 2,312 Bcfe at December 31, 2011. The remaining 26%, or 1,061 Bcfe, were located in the Southern Region at December 31, 2012, compared to 36% or 1,302 Bcfe at December 31, 2011. Approximately 54% of the proved reserves reported by QEP Energy at year end 2012 were developed. Approximately 33% of the total proved reserves at December 31, 2012, were comprised of crude oil and NGL up from 24% at December 31, 2011.

During the third quarter of 2012, QEP Energy acquired oil and gas properties in the Williston Basin for an aggregate purchase price of $1.4 billion, subject to post-closing adjustments (the 2012 Acquisition). The acquired properties consist of approximately 27,600 net acres of producing and undeveloped oil and gas properties in the active play area for the Bakken and Three Forks Formations within the Williston Basin. The acquired properties added 313.8 Bcfe of proved reserves during 2012.
 
QEP Energy faces competition in every part of its business, including the acquisition of producing leaseholds and wells and undeveloped leaseholds, the marketing of natural gas and oil, and the procurement of 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.

The Company seeks to acquire, develop and produce natural gas and oil from resource plays in its core areas. 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 rates. QEP Energy also continues to conduct some exploratory drilling to determine the commerciality of its inventory of unproven leaseholds. 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 in order to expand its presence in its core areas or to create new core areas.
 
QEP Energy, both directly and through QEP Marketing, sells its natural gas, crude oil and NGL production to a variety of customers, including gas-marketing firms, industrial users, local-distribution companies, crude oil refiners and remarketers. QEP Energy regularly evaluates counterparty credit and may require financial guarantees or prepayments from parties that fail to meet its credit criteria.

Midstream Field Services – QEP Field Services Company
 
QEP owns midstream (gathering, processing and treating) systems to complement its exploration and production operations in most of the 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 its products by 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 fee-based gathering, processing and keep-whole processing agreements. For 2013, QEP plans to allocate approximately 7% if its capital budget to QEP Field Services to grow its midstream business, including completing the construction of its gathering system in the Uinta Basin as well as the 10,000 Bbl/d expansion of the NGL fractionator located at the Blacks Fork processing complex (expected to be completed in the second half of 2013).

The following map illustrates QEP Field Services' areas of operations and the locations corresponding with QEP Energy's operating areas:


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QEP Field Services generated approximately 20%, 23% and 18% of the Company's Adjusted EBITDA (refer to Item 7 of Part II of this Annual Report on Form 10-K for management's definition and a reconciliation to net income of this non-GAAP financial measure) in the years ended December 31, 2012, 2011 and 2010, 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. RGS gathers natural gas for the Pinedale Anticline and the 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. The Rendezvous Pipeline Co., LLC (Rendezvous Pipeline), a wholly owned subsidiary of QEP Field Services, operates a Federal Energy Regulatory Commission (FERC) regulated, 21-mile, 20-inch-diameter gas transmission 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).
 
Fee-based gathering and processing revenues represented 77%, 70% and 78% of QEP Field Services' net operating revenues (revenues less plant shrink and transportation costs) during the years ended December 31, 2012, 2011 and 2010, respectively. Approximately 41%, 35%, and 36% of QEP Field Services' 2012, 2011 and 2010 net gas processing revenues (processing revenues less plant shrink) were derived from fee-based processing agreements. The remaining revenues were derived from keep-whole processing agreements. A keep-whole contract exposes QEP Field Services to frac-spread risk while a fee-based contract eliminates direct commodity price exposure. To further reduce volatility associated with keep-whole contracts, QEP Field Services may enter into forward-sales contracts for NGL or NGL price derivatives and equivalent gas volume derivatives with the intent to lock in a processing margin.
 
QEP Field Services faces regional competition with varying competitive factors in each basin. QEP Field Services' gathering and processing business competes with interstate and intrastate pipelines, producers and independent gatherers and processors. Numerous factors impact a customer's choice of a gathering or processing service 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, the Williston Basin and in northwest Louisiana. In addition to its natural gas operations, QEP Field Services also provides crude oil and water gathering and handling to affiliates and third-party producers in the Rocky Mountain region and the Williston Basin. QEP Field Services' gas gathering, processing and treating services are generally provided under long-term agreements.



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Energy Marketing—QEP Marketing Company
 
QEP Marketing provides wholesale marketing and sales of affiliate and third-party natural gas, oil and NGL and generated less than 1% of the Company's Adjusted EBITDA (refer to Item 7 of Part II of this Annual Report on Form 10-K for management's definition and a reconciliation to net income of this non-GAAP financial measure) in all of the years ended December 31, 2012, 2011 and 2010. As a wholesale marketing entity, QEP Marketing concentrates on markets in the Rocky Mountains 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 storage facility in northeast Utah.
 
QEP Marketing, through its wholly owned subsidiary Clear Creek Storage Company, LLC, (Clear Creek) 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.
 
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's natural gas and volumes purchased from third parties to wholesale marketers, industrial end-users and utilities. QEP Marketing sells QEP Energy's 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.
 
Government Regulation

QEP's business operations are subject to regulation under a wide range of local, state, tribal and federal statutes, rules, orders and regulations. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects its profitability. While QEP believes that it is in substantial compliance with currently applicable laws and regulations and has not experienced any material adverse effect arising from these requirements, there is no assurance that this trend will continue in the future. 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 QEP's operations. See additional discussion of regulations under Item 1A - Risk Factors, in this Annual Report on Form 10-K.

Regulation of Exploration, Production, Gathering and Processing Activities
The regulation of oil and gas exploration and production is a broad and increasingly complex area, notably including laws and regulations governing the discharge or release of materials into the environment or otherwise relating to environmental protection. These laws and regulations include the following:

Clean Air Act. The Clean Air Act and similar state laws regulate the emission of air pollutants from equipment and facilities employed by QEP Energy in its business, including but not limited to engines, tanks, dehydrators and gas processing plant components.

Greenhouse Gases Regulations and Climate Change Legislation. The Environmental Protection Agency (EPA) published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (GHG) present an endangerment to public health and the environment because such emissions are, according to the EPA, contributing to the warming of the earth's atmosphere and other climate changes. Based on these findings, the EPA adopted regulations for the measurement and reporting of GHG emitted from certain large facilities. In November 2010, the EPA expanded its GHG Reporting Rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis. In addition, both houses of Congress have considered legislation in recent years to reduce emissions of GHG, and a number of states have already taken legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, greenhouse gas permitting and/or regional GHG cap and trade programs.  

Clean Water Act and Safe Drinking Water Act. The Clean Water Act and similar state laws regulate discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams, as well as discharges to storm water. 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. The Safe Drinking Water Act (SDWA) and comparable state statutes restrict the disposal, treatment or release of water produced or used during oil and gas development.


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Oil Pollution Act of 1990. The Oil Pollution Act of 1990 (OPA) and regulations issued under OPA impose strict, joint and several liability on "responsible parties" for removal costs and damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States.  

Comprehensive Environmental Response, Compensation and Liability Act of 1980. The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA or Superfund) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. 

Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act (RCRA) is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements and liability for failure to meet such requirements on a person who is either a "generator" or "transporter" of hazardous waste or on an "owner" or "operator" of a hazardous waste treatment, storage or disposal facility. RCRA and many state counterparts specifically exclude from the definition of hazardous waste "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy." It is possible, however, that certain exploration and production wastes now classified as non-hazardous could be classified as hazardous waste in the future. Any repeal or modification of the oil and gas exploration and production exemption would increase the volume of hazardous waste QEP is required to manage and dispose of, and would cause QEP, as well as its competitors, to incur increased operating expenses.
 
Hydraulic Fracturing Regulations. 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% water and sand, with the remaining constituents consisting of chemical 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. The Company supports disclosure of the contents of hydraulic fracturing fluids, and submits information regarding its wells and the fluids used in them to the national online disclosure registry, FracFocus (www.fracfocus.org).

The Company obtains water for fracture stimulations from a variety of sources including industrial water wells and surface water 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, 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. Additionally, the Bureau of Land Management (BLM) proposed in May 2012 new regulations regarding chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic fracturing, on federal and tribal land. There has been a heightened debate recently over whether the fluids used in hydraulic fracturing may contaminate drinking water supplies, and proposals have been made to revisit the environmental exemption for hydraulic fracturing under the SDWA or to enact separate federal legislation or legislation at the state and local government levels that would regulate hydraulic fracturing.

The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and 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 final results expected to be available by 2014. Moreover, the EPA announced in October 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 publicly owned treatment plant. In addition, the Department of Energy is conducting an investigation of practices the agency could recommend to better protect the environment from drilling employing hydraulic fracture stimulation.

Additionally, a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices, and recent Congressional legislative efforts seek to regulate hydraulic fracturing under the SDWA's Underground Injection Control program, which would significantly increase well capital costs. Certain members of Congress have also called upon (1) the Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources; (2) the Securities and Exchange Commission (SEC) to investigate the natural gas industry and any possible misleading of

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investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and (3) the 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. Air quality impacts from hydraulic fracturing practices are also being studied currently by various federal and state agencies. These various ongoing or proposed studies and investigations, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA, the Clean Air Act or other statutes and regulatory programs. 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).

Tribal Lands and Minerals. Various federal agencies within the U.S. Department of the Interior, particularly the BLM and the Bureau of Indian Affairs, along with certain Native American tribes, promulgate and enforce regulations pertaining to natural gas and oil operations on Native American tribal lands on which QEP Energy operates. These regulations include such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations.

Endangered Species Act, National Environmental Policy Act. The Endangered Species Act restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas. Many of QEP's operations are subject to the requirements of the National Environmental Policy Act (NEPA), and are therefore evaluated under NEPA for their direct, indirect and cumulative environmental impacts. This is done in Environmental Assessments or Environmental Impact Statements prepared for a lead agency under the Council on Environmental Quality and other agency regulations, usually for the BLM in the areas where QEP operates currently.

Emergency Planning and Community Right-to-Know Act and Occupational Safety and Health Act. The Emergency Planning and Community Right-to-Know Act (EPCRA) requires facilities to disseminate information on chemical inventories to employees as well as local emergency planning committees and emergency response departments. The Non-Government Organization Environmental Integrity Project has filed a petition for rulemaking with the EPA under the EPCRA and the federal Administrative Procedure Act to add the "Oil and Gas Extraction Industry" to the list of industries required to report releases of certain "toxic chemicals" under EPCRA's Toxics Release Inventory (TRI) program. The federal Occupational Safety and Health Act establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communication programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures.

Dodd-Frank Wall Street Reform and Consumer Protection Act. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was passed by Congress and signed into law in July 2010. The Dodd-Frank Act is designed to provide a comprehensive framework for the regulation of the over-the-counter derivatives market with the intent to provide greater transparency and reduction of risk between counterparties. The Dodd-Frank Act subjects swap dealers and major swap participants to capital and margin requirements and requires many derivative transactions to be cleared on exchanges. The Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end-users. In addition, in August 2012, the SEC issued a final rule under Section 1504 of the Dodd-Frank Act, Disclosure of Payments by Resource Extraction Issuers, which requires resource extraction issuers, such as QEP, to file annual reports that provide information about the type and total amount of payments made for each project related to the commercial development of oil, natural gas, or minerals to each foreign government and the federal government.  

Regulation of Transportation and Sales of Natural Gas

Natural Gas Act of 1938, Natural Gas Policy Act of 1978 and Energy Policy Act of 2005. The FERC regulates the transportation and sale for resale, of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 and regulations issued under those Acts. 
 
Other Regulations. QEP Field Services' construction and operation activities are subject to various local, state, federal and tribal rules and regulations. Most of these rules and regulations are administered by the Department of Transportation, the Occupational Safety and Health Administration, and the EPA.

Regulation of Transportation of Crude Oil by Pipeline

The Interstate Commerce Act (ICA), as applied to liquids pipelines, requires that rates and terms of service be just and reasonable and non-discriminatory. Under the ICA, FERC regulates the rates and terms and conditions of service for interstate movements of crude oil, natural gas liquids and refined petroleum products.


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

Significant Customers

The Company's five largest customers accounted for 37%, 32%, and 27% in aggregate, of QEP revenues during the years ended December 31, 2012, 2011 and 2010, respectively. During the year ended December 31, 2012, Chevron U.S.A. Inc. and Enterprise Products Operating, L.P. accounted for 13% and 10%, respectively, of the Company's total revenues. Management believes that the loss of either customer, or any other customer, would not have a material effect on the financial position or results of operations of QEP, since there are numerous potential purchasers of its production. During the years ended December 31, 2011 and 2010, each of the five largest customers sales were below 10% of QEP's total revenues.

Employees
 
At December 31, 2012, QEP Resources, Inc. had 936 employees compared to 876 employees at December 31, 2011. 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 19, 2013, are listed below:
Charles B. Stanley
 
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Chairman (2012 to present), President, and 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
 
54
 
Executive Vice President, Chief Financial Officer, and Treasurer 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
 
54
 
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).
Austin S. Murr
 
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Senior Vice President - Land and Business Development (2012 to present). Vice President - Land and Business Development (2010 - 2012). Previous titles with Questar: Vice President - Land and Business Development (2006 - 2010); Director of Business Development (2004 to 2006).
Perry H. Richards
 
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Senior Vice President – Field Services (2010 to present). Previous title with Questar: Vice President, Questar Gas Management (2005 to 2010).
Jim E. Torgerson
 
49
 
Senior Vice President - Operations (2012 to present). Previous title with QEP: Senior Vice President, Drilling and Completions (2011 to 2012). Previous titles with Questar: Vice President, Drilling and Completions (2009 to 2010); Vice President, Rockies Drilling and Completions (2005 to 2008).
Abigail L. Jones
 
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Vice President, Compliance and Corporate Secretary, QEP (2010 to present). Previous titles with Questar: Vice President Compliance (2007 to 2010); Corporate Secretary (2005 to 2010); Assistant Secretary (2004 to 2005).
Christopher K. Woosley
 
43
 
Vice President and General Counsel (2012 to present). Previous title with QEP: Senior Attorney (2010 to 2012). Prior to joining QEP, Mr. Woosley was a partner in the law firm Cooper Newsome & Woosley PLLP (2003 to 2010).
Margo Fiala
 
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Vice President - Human Resources (2010 to present). Prior to joining QEP, Ms. Fiala held a variety of roles at Suncor Energy (1995 to 2010) and most recently was the Director of Human Resources for Suncor Energy U.S.A. (2004 to 2010).


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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 Company's Board of Directors. There is no arrangement or understanding under which the officers were selected.

ITEM 1A. RISK FACTORS
 
Investors should read carefully the following factors as well as the cautionary statements referred to in "Forward-Looking Statements" herein. If any of the risks and uncertainties described below or elsewhere in this Annual Report actually occur, the Company's business, financial condition or results of operations could be materially adversely affected.
 
The 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 and weather forecasts. 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, oil and NGL from unconventional sources on the global and local energy supply;
domestic political developments and actions;
weather conditions and weather forecasts;
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 years ended December 31, 2012 and 2011, QEP recorded impairment charges of $107.6 million and $195.5 million, respectively, on its proven properties and $23.7 million and $20.3 million, respectively, on its unproven properties. See Part I, Item 8, Note 1 - Summary of Significant Accounting Policies, of this Annual Report on Form 10-K for additional information.
 
Slower economic growth rates in the U.S. may materially adversely impact QEP's operating results. The U.S. 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 could be significant long-term effects resulting from the financial crisis and recession, including a future global economic growth rate that is slower than that 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 has encouraged countries with large federal budget deficits, such as the U.S., 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.

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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 experience relatively steep declines 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 reflective of 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 production, 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, and increasing prices for, oilfield equipment, services and qualified personnel could impact results of operations. The demand for and availability of qualified and experienced personnel to drill wells and conduct field operations, in addition to geologists, geophysicists, engineers, landmen 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:
 
injuries and/or deaths of employees, supplier personnel, or other individuals;
fire, explosions and blow-outs;
unexpected drilling conditions such as abnormally pressured formations;
pipe, cement or casing failures;
title disputes;
equipment malfunctions and/or mechanical failure on high-volume wells;
security breaches, cyber attacks, piracy, or terroristic acts;
theft or vandalism of oilfield equipment and supplies, especially in areas of increased activity;
severe weather that could affect our operations;
plant, pipeline, and other facility accidents and failures; and
environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of air pollutants, brine water or well fluids into the environment, including from hydraulic fracturing activities.

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 compliance investigations; fines or curtailment of operations;

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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 from operations 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. 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 with industry practice, operators generally indemnify drilling contractors and oilfield service companies (collectively, contractors) against certain losses suffered by the operator and third parties resulting from a well blowout or fire or other uncontrolled flow of hydrocarbons, regardless of the relative fault of the contractor. Therefore, QEP may be liable, regardless of the fault of the contractor, for some or all of the costs of controlling a blowout, drilling a relief and/or replacement well and the cleanup of any pollution or contamination resulting from a blowout as well as for claims for personal injury or death suffered by QEP's employees and others. QEP's drilling contracts and oilfield service agreements, however, generally provide that the contractor will indemnify QEP for claims related to injury and death of employees of the contractor and its subcontractors and for property damage suffered by the contractor and its contractors.

As is also 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 may exceed coverage limits.
 
Certain of QEP's undeveloped leasehold assets are subject to lease agreements that will expire over the next several years unless production is established on units containing the acreage.
Leases on natural gas and oil properties typically have a term of three to five years after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If QEP's leases expire and QEP is unable to renew the leases, QEP will lose its right to develop the related reserves. While QEP seeks to actively manage its leasehold inventory by drilling sufficient wells to hold the leases that it believes are material to its operations, QEP's drilling plans are subject to change based upon various factors, including drilling results, natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

Lack of availability of pipeline and other transportation capacity could impact results of operations. The lack of availability of satisfactory oil, natural gas and NGL transportation facilities 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; or depending on the specific lease provisions, some leases could terminate. If pipeline quality requirements change, QEP might be required to install or contract for 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 by QEP to third parties under its 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 NGL are curtailed or cut off. Force

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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 been volatile, making terms for certain types of financings difficult to predict, and in certain cases, resulting in certain types of financing being unavailable. If QEP's revenues decline as a result of lower natural gas, oil or 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 manage the interest rate on a portion of its floating-rate debt. The interest rates for the Company's revolving credit facility are tied to QEP's ratio of indebtedness to Consolidated EBITDAX (as defined in the credit agreement). QEP's failure to obtain additional financing could result in a curtailment of its operations relating to exploration and development of its prospects or construction of new oil and gas processing facilities, 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.
 
A downgrade in QEP's credit rating could negatively impact QEP's cost of and ability to access capital. Although QEP is not aware of any current plans of credit rating agencies to lower their ratings on QEP's debt, QEP's credit ratings may be subject to future downgrades. A downgrade of credit ratings may make it more difficult or expensive to raise capital from financial institutions or other sources. A downgrade in QEP's credit rating below a certain level could limit the amount of debt that QEP may incur. In addition, a downgrade could affect QEP's requirements to provide financial assurance of its performance under certain contractual arrangements and derivative agreements.

QEP's debt and other financial commitments may limit its financial and operating flexibility. QEP's total debt was approximately $3.2 billion at December 31, 2012. QEP also has various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services and products. QEP's financial commitments could have important consequences to its business including, but not limited to, limiting QEP's ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, to pay dividends to shareholders, or to otherwise realize the value of its assets and opportunities fully because of the need to dedicate a substantial portion of its cash flows from operations to payments on its debt or to comply with any restrictive terms of its debt. Additionally, the credit agreements governing QEP's revolving credit facility and term loan facility contain a number of covenants that impose constraints on the Company, including restrictions on QEP's ability to dispose of assets, make certain investments, and incur liens.

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 purchasers of its production, 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 to oil and gas drilling and development activity has been growing globally and is particularly pronounced in the U.S. 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, among other things, reduce access to federal and state government lands and delay

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or cancel certain projects such as the development of oil or gas shale plays. For example, environmental activists continue to advocate for increased regulations on shale drilling in the U.S., even in jurisdictions that are among the most stringent in their regulation of the industry. Future activist efforts could result in the following:
 
delay or denial of drilling and other necessary permits;
shortening of lease terms or reduction in lease size;
restrictions on installation or operation of production, gathering or processing facilities;
setback requirements from houses, schools and businesses;
towns, cities, states and counties considering bans on certain activities, including hydraulic fracturing;
restrictions on the use of certain operating practices, such as hydraulic fracturing, or the disposition of related waste materials, such as hydraulic fracturing fluids and produced water;
increased severance and/or other taxes;
cyber attacks;
legal challenges or lawsuits;
negative publicity about QEP;
increased costs of doing business;
reduction in demand for QEP's products; and
other adverse effects on QEP's ability to develop its properties and increase 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.
 
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 and returns on capital 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. Additional financial regulations 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 are 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 has incurred significant unrealized gains and losses in prior periods and may continue to incur these types of gains and losses in the future.
 
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 QEP's counterparty's assessment of QEP's credit risk.

Relative changes in NGL and natural gas prices may adversely impact QEP's results due to changes in the frac spread. Approximately 23%, 30% and 22% of QEP Field Services' net operating revenues for the years ended December 31, 2012, 2011 and 2010, respectively, were derived from keep-whole processing agreements. Under QEP's keep-whole processing contracts, QEP is exposed to the frac spread and transportation and fractionation exposure from firm transportation constraints. 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" would result 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 ethane price and margin, which historically have been more volatile than the price of other NGL products, including propane, butane and gasoline. QEP's competitors have also made significant investments in gas processing plants that recover significant volumes of ethane. The U.S. ethane market is currently oversupplied, and probably will remain oversupplied in the foreseeable 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

19



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 may 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.

If QEP's plan to separate a majority of its gathering assets in Wyoming and North Dakota into a new publicly traded master limited partnership is delayed or not completed, QEP's stock price may decline and its growth potential may not be enhanced. In January 2013, QEP announced a plan to separate a majority of its gathering assets in Wyoming and North Dakota into a new publicly traded master limited partnership (“MLP”) and to file an initial registration statement in connection with this planned initial public offering in the second quarter of 2013. Completion of this plan is subject to market conditions and numerous other risks beyond QEP's control, including, but not limited to, the general economy, credit markets, equity markets, energy prices, regulatory approvals, compliance with contractual obligations, and future opportunities that QEP's board of directors may determine present greater potential value to stockholders than the planned MLP. Therefore, it is possible that QEP will not file a registration statement for an initial public offering, that the MLP will not complete an offering of securities, and that QEP will not be able to complete its proposed actions on the desired timetable. If the transaction is not completed or delayed, QEP's stock price may decline and its growth potential may not be enhanced. If completed, QEP's plan to separate portions of gathering assets may not achieve its intended results. QEP's announcement of this plan did not, and this risk factor does not, constitute an offer to sell or the solicitation of an offer to buy any securities and shall not constitute an offer, solicitation or sale in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of that jurisdiction.
 
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;
U.S. independent oil and gas companies;
service companies engaging in oil and gas exploration and production activities; and
private equity funds investing in oil and gas assets.

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 critical 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 natural gas and crude 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 unable to make acquisitions, successfully integrate acquired businesses and/or assets, or adjust to the effects of divestitures, causing a disruption to its business. One aspect of QEP's business strategy calls for acquisitions of businesses and assets that complement or expand QEP's current business, such as QEP's 2012 Acquisition in the Williston Basin. This may present greater risks for QEP than those faced by peer companies that do not consider acquisitions as a part of their business strategy. QEP cannot provide assurance that it will be able to identify acquisition opportunities. Even if QEP does identify acquisition opportunities, it may not be able to complete the acquisitions due to capital constraints. Any acquisition of a business or assets involves potential risks, including, among others:

difficulty integrating the operations, systems, management and other personnel and technology of the acquired business with QEP's own;
the assumption of unidentified or unforeseeable liabilities, resulting in a loss of value;

20



the inability to hire, train or retain qualified personnel to manage and operate QEP's growing business and assets; or
a decrease in QEP's liquidity to the extent it uses a significant portion of its available cash or borrowing capacity to finance acquisitions or operations of the acquired properties.
 
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.
 
QEP may be unable to dispose of non-core, non-strategic assets on financially attractive terms, resulting in reduced cash proceeds and/or losses. QEP's business strategy also includes sales of non-core, non-strategic assets. QEP continually evaluates its portfolio of assets related to capital investments, divestitures and joint venture opportunities. Various factors can materially affect QEP's ability to dispose of assets on terms acceptable to QEP. Such factors include current commodity prices, laws, regulations and the permitting process impacting oil and gas operations in the areas where the assets are located, willingness of the purchaser to assume certain liabilities such as asset retirement obligations, QEP's willingness to indemnify buyers for certain matters, and other factors. Inability to achieve a desired price for the assets, or underestimation of amounts of retained liabilities or indemnification obligations, can result in a reduction of cash proceeds, a loss on sale due to an excess of the asset's net book value over proceeds, or liabilities that must be settled in the future at amounts that are higher than QEP had expected.
 
QEP is involved in legal proceedings that may result in substantial liabilities. Like many oil and gas companies, QEP is involved in various legal proceedings, such as title, royalty, and contractual disputes, in the ordinary course of its business. The cost to settle legal proceedings or any resulting judgment against QEP in such proceedings could result in a substantial liability, which could materially and adversely impact QEP's cash flows and operating results for a particular period. Current accruals for such liability may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal proceedings could change from one period to the next and such changes could be material.

Failure of the Company's controls and procedures to detect errors 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 errors 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 being 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.
 
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 federal, state, tribal and local tax, energy, environmental, health and safety laws and regulations. The failure to comply with applicable laws and regulations can result in substantial penalties and may threaten the Company's authorization to operate.

Environmental laws and regulations are complex, change frequently and have tended to become more onerous over time. The regulatory burden on the Company's operations increases its cost of doing business and, consequently, affects its profitability. 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 QEP's 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 limit the scope of QEP's planned operations.
 
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 in its operations on federal lands. Various wildlife species inhabit QEP Energy's leaseholds at Pinedale and in other areas. The presence of wildlife or plants, including species that are protected under the federal Endangered Species Act, could limit access

21



to leases held by QEP Energy on public and other lands. Many of QEP's operations are subject to the requirements of the National Environmental Policy Act (NEPA), and are therefore evaluated under NEPA for their direct, indirect and cumulative environmental impacts. This is done in Environmental Assessments or Environmental Impact Statements prepared for a lead agency under Council on Environmental Quality and other agency regulations, usually for the BLM in the areas where QEP operates currently. 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 to which QEP Energy is subject.

Several of QEP Field Services' transportation facilities are subject to 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. Additionally, FERC has jurisdiction over the operation of QEP Marketing's Clear Creek storage facility 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.

Section 1(b) of the Natural Gas Act exempts gathering activities from regulation or jurisdiction by the 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 QEP Field Services' 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 Field Services therefore cannot guarantee that the jurisdictional status of its gathering systems will remain unchanged. QEP's gas gathering systems are not currently subject to state utility regulations. The FERC has jurisdiction under the Energy Policy Act of 2005 to impose rules and regulations applicable to all natural gas market participants to ensure market transparency.

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. The U.S. President's Fiscal Year 2013 Budget Proposal includes provisions
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 include (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. 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.
 
Environmental laws are complex and potentially burdensome for QEP's operations. QEP must comply with numerous and complex federal, state and tribal regulations governing activities on federal, state and tribal lands, notably including the Clean Air Act, the Clean Water Act, the SDWA, OPA, CERCLA, RCRA, NEPA, the Endangered Species Act, the National Historic Preservation Act and similar state laws and tribal codes. Federal, state and tribal regulatory agencies frequently impose conditions on the Company's activities under these laws. These restrictions have become more stringent over time and can limit or prevent exploration and production on significant portions of the Company's leasehold. These laws also allow certain environmental groups to oppose drilling on some of QEP's federal and state leases. These groups sometimes sue federal and state regulatory agencies and/or the Company under these laws for alleged procedural violations in an attempt to stop, limit or delay natural gas and oil development on public and other lands.
 
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. For example, QEP's drilling operations in the Powder River Basin in Wyoming continue to be delayed due to an over two-year backlog of permit applications. Further, the public may comment on and otherwise seek to influence the permitting process, including through intervention in the courts. Accordingly, necessary 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.

Federal and state hydraulic fracturing legislation or regulatory initiatives could increase QEP's costs and restrict its access to natural gas and oil reserves. Currently, all well construction activities, including hydraulic fracture stimulation, are

22



regulated by state agencies that review and approve all aspects of natural gas and oil well design and operation. The EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal SDWA and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. The EPA appears to be considering its existing regulatory authorities for possible avenues to further regulate hydraulic fracturing fluids and/or the components of those fluids. Additionally, the Bureau of Land Management proposed in May 2012, new regulations regarding chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic fracturing, on federal and tribal lands. Legislation has also 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, notwithstanding the proposed and ongoing rulemaking proceedings noted above. 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 regulations, 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.
 
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 and completion 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 fracture stimulation 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. 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.
 
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. 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 and crude oil. QEP's ability to access and develop new natural gas and crude oil reserves may be restricted by climate-change regulation, including GHG reporting and regulation. Legislative bills have been proposed 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 EPA has adopted final regulations for the measurement and reporting of GHG emitted from certain large facilities. 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 are required to obtain major source permits. In addition, several of the states in which QEP operates are considering various GHG registration and reduction programs. While additional 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.
 
The adoption and implementation of new statutory and regulatory requirements for swap transactions could have an adverse impact on QEP's ability to mitigate risks associated with its business and increase the working capital requirements to conduct these activities. The Dodd-Frank Act, which was passed by Congress and signed into law in July 2010, contains significant derivatives regulation. QEP is currently evaluating the final rules of the Commodity Futures Trading Commission and assessing the impact on the Company's risk management program. QEP believes it will meet the requirements for the commercial end-user clearing exception and be able to continue to execute derivative transactions and not be required to meet the mandated clearing requirements.

QEP will need to expend significant resources complying with and adapting to the new regulatory regime, including significant reporting and record keeping requirements, as well as otherwise ensuring that QEP continues to be able to rely on certain exemptions from mandatory clearing requirements. In addition, the changes to the swap market as a result of the implementation of the Dodd-Frank Act could significantly increase the cost of entering into new swaps or maintaining existing

23



swaps, materially alter the terms of new or existing swap transactions, impose additional documentation requirements, and/or reduce the availability of new or existing swaps.
 
Depending on the final form of the margin rules for uncleared swaps and whether swap dealers elect to collect margin from end-user clients even if there is no requirement to do so under the Dodd-Frank Act, QEP might in the future be required to provide cash collateral for its commodity derivative transactions under circumstances in which it does not currently post cash collateral. Requirements to post cash collateral could not only cause significant liquidity issues by reducing QEP'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. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices. QEP's revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on QEP's consolidated financial position, results of operations or cash flows.

General economic and other conditions impact QEP's results. QEP's results may also be negatively affected by: changes in global economic conditions; availability and economic viability of gas and oil properties for sale or exploration; 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; and terrorist attacks or acts of war.
 
The Company's pension plans are currently underfunded and may require large contributions, which may divert funds from other uses. QEP has a closed defined benefit pension plan that covers 145, or 16%, of QEP's active employees and 70 participants that are retired, terminated and vested, or suspended. 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, 2012 and 2011, QEP's pension plans were underfunded by $74.4 million and $59.9 million, respectively. The underfunded status of QEP's pension plans may require that the Company make large contributions to such plans. QEP made cash contributions of $6.9 million and $14.8 million during the years ended December 2012 and 2011, respectively, to its defined benefit pension plans and expects to make contributions of approximately $11.3 million to its pension plans in 2013. 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.

QEP is subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss. The oil and gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, QEP depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering and processing systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. Pipelines, refineries, power stations and distribution points for both fuels and electricity are becoming more interconnected by computer systems. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. QEP's technologies, systems, networks, and those of its vendors, suppliers and other business partners may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of its business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. QEP's systems and insurance coverage for protecting against cyber security risks may not be sufficient.

ITEM 1B. UNRESOLVED STAFF COMMENTS
 
None.



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ITEM 2. PROPERTIES

Exploration and Production - QEP Energy
 
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).
 
Northern Region
 
Pinedale
In 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10-acre density drilling for Lance Pool wells on about 12,700 gross acres (8,091 net acres) of QEP Energy's 17,115 gross acres (11,601 net acres) Pinedale leasehold. In January 2008, the WOGCC approved five-acre density drilling for Lance Pool wells on about 4,200 gross acres (2,677 net acres) of QEP Energy's Pinedale leasehold. On March 13, 2012, the WOGCC approved five-acre density drilling for Lance Pool wells on approximately 7,200 additional gross acres (4,317 net acres). The area approved for increased density corresponds to the currently estimated economic productive limits of QEP Energy core acreage in the field. 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 more than 900 additional wells will be required to fully develop its Pinedale acreage on 5 to 10-acre density. At December 31, 2012, QEP Energy had four operated rigs drilling in the Pinedale Anticline. In addition to QEP Energy's 715 gross producing wells, QEP Energy has an overriding royalty interest only in an additional 21 wells at Pinedale.
 
Williston Basin
QEP has approximately 117,000 net acres of leaseholds in the Williston Basin in western North Dakota, where the Company is targeting the Bakken and Three Forks formations. During the third quarter of 2012, QEP Energy closed the 2012 Acquisition, which added 27,600 net acres of producing leasehold in the Williston Basin. As a result of the 2012 Acquisition and development drilling on existing acreage, Williston Basin reserves represent 16% of the Company's total reserves. Accordingly, Williston Basin reserves and production are shown separately from Legacy's results in the years presented. 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, 2012, QEP Energy had five operated rigs drilling in the Williston Basin.

Uinta Basin
The majority of Uinta Basin proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs at depths of 4,500 feet to deeper than 18,000 feet. QEP Energy owns working interests in approximately 257,000 net leasehold acres in the Uinta Basin. QEP Energy had three operated rigs drilling in the Uinta Basin at December 31, 2012, two of which were targeting the Lower Mesaverde Formation productive fairway in the Red Wash Unit, in which QEP holds 32,300 net acres, and the other drilling various vertical and horizontal oil targets.
 
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 Legacy. Exploration and development activity in 2012 included wells in the Powder River and Greater Green River Basins in Wyoming.

Southern Region
 
Haynesville/Cotton Valley
QEP Energy has approximately 50,700 net acres of Haynesville Shale leaseholds in northwest Louisiana and additional lease rights that cover the Hosston and Cotton Valley formations. 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 since the 1990's. As of December 31, 2012, due to depressed natural gas prices, QEP Energy did not have any operated rigs drilling in the Haynesville/Cotton Valley area.
 
Midcontinent
QEP Energy's Midcontinent operations 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.
 

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QEP Energy has approximately 76,000 net acres of Woodford "Cana" Shale leaseholds in western Oklahoma. 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, 2012, QEP Energy had two operated rigs drilling in the Woodford/Cana play.
 
QEP Energy has approximately 35,000 net acres of Granite Wash/Atoka Wash leaseholds in the Texas Panhandle and western Oklahoma and has been drilling vertical Granite Wash/Atoka Wash wells for over a decade. 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 uneconomic wells. As of December 31, 2012, QEP Energy had one rig drilling in oil and liquids-rich gas plays in the Texas Panhandle.
 
Reserves – QEP Energy
 
At both December 31, 2012 and 2011, approximately 91% of QEP Energy's estimated proved reserves were Company operated. Proved developed reserves represented 54% of the Company's total proved reserves at both December 31, 2012 and 2011, while the remaining 46% of reserves were classified as proved undeveloped at both December 31, 2012 and 2011. All reported reserves are located in the U.S. 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 proved reserves are summarized as follows:
 
 
December 31, 2012
 
December 31, 2011
 
 
Natural
 Gas
 
Oil
 
NGL
 
Natural Gas
Equivalents (1)
 
Natural
Gas
 
Oil
 
NGL
 
Natural Gas
Equivalents (1)
 
 
(Bcf)
 
(MMbbl)
 
(MMbbl)
 
 (Bcfe)
 
(Bcf)
 
(MMbbl)
 
(MMbbl)
 
(Bcfe)
Proved developed reserves
 
1,531.7

 
47.4

 
49.3

 
2,111.9

 
1,538.3

 
33.0

 
38.4

 
1,966.3

Proved undeveloped reserves
 
1,090.7

 
71.6

 
50.6

 
1,824.2

 
1,211.1

 
34.6

 
38.2

 
1,647.5

Total proved reserves
 
2,622.4

 
119.0

 
99.9

 
3,936.1

 
2,749.4

 
67.6

 
76.6

 
3,613.8

____________________________
(1) 
Oil and NGL are converted to natural gas equivalents at the ratio of one bbl of crude oil, condensate or NGL to six Mcf of equivalent natural gas.

QEP Energy's reserve, production and production life index for each of the years ended December 31, 2010, through December 31, 2012, is summarized below:
Year ended
December 31,
 
Year End
Reserves (Bcfe)
 
Natural Gas, Oil
and NGL Production (Bcfe)
 
Reserve Life
Index (1) (Years)
2010
 
3,030.7
 
229.0
 
13.2
2011
 
3,613.8
 
275.2
 
13.1
2012
 
3,936.1
 
319.2
 
12.3
 ____________________________
(1)
Reserve life index is calculated by dividing year-end proved reserves by production for that year.

Proved Reserves 
Reserve and related information is presented consistent with the requirements of the SEC's rules for the Modernization of Oil and Gas Reporting. These 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 commodity prices, adjusted for location and quality differentials, for the prior 12 months (unless contractual arrangements designate the price) 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 17 - Supplemental Gas and Oil Information (unaudited), of in Item 8 of Part II of this Annual Report for additional information regarding estimates of proved reserves and the preparation of such estimates.
 

26



QEP Energy's proved reserves in major operating areas are summarized below:
 
 
December 31,
 
 
2012
 
2011
Northern Region
 
(Bcfe)
 
(% of total)
 
(Bcfe)
 
(% of total)
Pinedale
 
1,530.8

 
39
%
 
1,531.0

 
42
%
Williston Basin
 
614.7

 
16
%
 
259.0

 
7
%
Uinta Basin
 
617.9

 
16
%
 
393.6

 
11
%
Legacy
 
112.2

 
3
%
 
128.6

 
4
%
Southern Region
 
 
 
 
 
 
 
 
Haynesville/Cotton Valley
 
530.5

 
13
%
 
782.9

 
22
%
Midcontinent
 
530.0

 
13
%
 
518.7

 
14
%
Total QEP Energy
 
3,936.1

 
100
%
 
3,613.8

 
100
%
 
Estimates of the quantity of proved reserves increased during 2012, primarily related to reserve additions in the Williston and Uinta Basins, offset by decreases in estimated Haynesville/Cotton Valley proved reserves. The increase in Williston Basin reserves was primarily the result of the 2012 Acquisition, while increases in the Uinta Basin were attributable to extensions and additions from the recognition of additional proved undeveloped locations due to QEP's increased drilling program. The Haynesville/Cotton Valley decrease was primarily related to downward pricing related revisions, resulting from lower natural gas prices mostly related to proved undeveloped reserves.
 
Proved Undeveloped Reserves
Significant changes to proved undeveloped reserves (PUDs) occurring during 2012, are summarized in the table below:
 
2012
 
(Bcfe)
Proved undeveloped reserves at January 1,
1,647.5

Transferred to proved developed reserves
(255.6
)
Purchase of reserves in place
225.1

Revisions to previous estimates (1)
(283.5
)
Extensions and discoveries
490.7

Proved undeveloped reserves at December 31, (2)
1,824.2

 ____________________________
(1) 
The decrease was primarily related to downward pricing related revisions for Haynesville/Cotton Valley, resulting from lower natural gas prices.
(2) 
All of QEP Energy's PUDs at December 31, 2012, are scheduled to be developed within five years from the date such locations were initially disclosed as PUDs, except for 200 Bcfe of reserves 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 require 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 PUDs were approximately $513.0 million, $533.6 million and $434.2 million for the years ended December 31, 2012, 2011 and 2010, respectively. The costs incurred in 2012 related to the drilling of PUDs in QEP's development projects. This investment resulted in the transfer in 2012 of 255.6 Bcfe of reserves from proved undeveloped to proved developed, representing 16% of the Company's total proved undeveloped reserves as of December 31, 2011.
 
Estimated future development costs relating to the development of PUDs are projected to be approximately $1,042.5 million in 2013, $871.1 million in 2014 and $814.5 million in 2015. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. PUDs related to major development projects will be reclassified to proved developed reserves when production commences.

27




Internal Controls Over Proved 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 reporting 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 proved reserves as of December 31, 2012, 2011 and 2010. The individual at Ryder Scott who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2012, is a registered Professional Engineer in the State of Colorado and graduated with a Masters of Science degree in Geological Engineering 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 99.1 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 is our Chief Engineer. This individual is a member of the Society of Petroleum Engineers and graduated with a Bachelors of Science degree in Geological Engineering from South Dakota School of Mines and Technology in 1979. He is a registered Professional Petroleum Engineer in the state of Colorado. This individual has over 30 years experience in the Petroleum Industry, including more than 20 years reservoir engineering experience in most of the active domestic basins in the U.S.
 
To establish reserves, the SEC allows a company to use technologies 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 have been field tested and have 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, volumetric methods or a combination of methods.

All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. Performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical production data available through December 2012 in those cases where such data were considered to be definitive. For wells currently on production, forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Approximately 99% of QEP's proved developed non-producing and undeveloped reserves included in this Annual Report on Form 10-K were estimated by analogy. The remaining one percent of such reserves were estimated by the volumetric method. The volumetric analysis utilized pertinent well data furnished to Ryder Scott by QEP or obtained from available public data sources through December 2012. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by QEP. Wells or locations that are not currently producing may start producing earlier or later than anticipated in these estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. Some combination of these methods is used to determine reserve estimates in substantially all of QEP's fields.
 
Refer to Note 17 - Supplemental Gas and Oil Information (Unaudited), of the consolidated financial statements included in Item 8 of Part II of this Annual Report on Form 10-K 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, 2012, 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.
 

28



Production, Production Prices and Production Costs
The following table sets forth the net production volumes, the field-level 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, 2012, 2011 and 2010:
 
 
 
Year Ended December 31,
 
 
2012
 
2011
 
2010
QEP Energy
 
 
Volumes produced and sold
 
 
 
 
 
 
Natural gas (Bcf)
 
249.3

 
236.4

 
203.8

Oil (MMbbl)
 
6,306.9

 
3,741.3

 
2,979.8

NGL (MMbbl)
 
5,349.0

 
2,715.6

 
1,225.8

Total equivalent production (Bcfe)
 
319.2

 
275.2

 
229.0

Average field-level price (1)
 
 

 
 

 
 

Natural gas (per Mcf)
 
$
2.68

 
$
3.95

 
$
4.18

Oil (per bbl)
 
84.45

 
86.20

 
69.39

NGL (per bbl)
 
34.43

 
47.76

 
39.04

Lifting costs (per Mcfe)
 
 

 
 

 
 

Lease operating expense
 
$
0.55

 
$
0.54

 
$
0.56

Production taxes
 
0.30

 
0.36

 
0.34

Total lifting costs
 
$
0.85

 
$
0.90

 
$
0.90

 ____________________________
(1) 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:
 
 
Year ended December 31,
 
Change
 
 
2012
 
2011
 
2010
 
2012 vs. 2011
 
2011 vs. 2010
QEP Energy - Natural gas (Bcf)
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
Pinedale
 
77.4

 
69.3

 
65.1

 
8.1

 
4.2

Williston Basin
 
0.9

 
0.1

 

 
0.8

 
0.1

Uinta Basin
 
16.3

 
14.9

 
14.9

 
1.4

 

Legacy
 
11.4

 
12.1

 
13.7

 
(0.7
)
 
(1.6
)
Southern Region
 
 
 
 

 
 
 
 
 
 
Haynesville/Cotton Valley
 
112.0

 
107.1

 
79.3

 
4.9

 
27.8

Midcontinent
 
31.3

 
32.9

 
30.8

 
(1.6
)
 
2.1

Total production
 
249.3

 
236.4

 
203.8

 
12.9

 
32.6

 

29



A summary of oil production by major geographical area is shown in the following table:
 
 
Year ended December 31,
 
Change
 
 
2012
 
2011
 
2010
 
2012 vs. 2011
 
2011 vs. 2010
QEP Energy - Oil (Mbbl)
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
Pinedale
 
664.4

 
583.8

 
551.8

 
80.6

 
32.0

Williston Basin
 
3,029.5

 
1,133.5

 
478.7

 
1,896.0

 
654.8

Uinta Basin
 
890.9

 
866.7

 
957.1

 
24.2

 
(90.4
)
Legacy
 
297.6

 
271.0

 
269.5

 
26.6

 
1.5

Southern Region
 
 

 
 

 
 
 
 
 
 
Haynesville/Cotton Valley
 
43.4

 
51.0

 
78.4

 
(7.6
)
 
(27.4
)
Midcontinent
 
1,381.1

 
835.3

 
644.3

 
545.8

 
191.0

Total production
 
6,306.9

 
3,741.3

 
2,979.8

 
2,565.6

 
761.5


A summary of NGL production by major geographical area is shown in the following table:
 
 
Year ended December 31,
 
Change
 
 
2012
 
2011
 
2010
 
2012 vs. 2011
 
2011 vs. 2010
QEP Energy - NGL (Mbbl)
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
Pinedale
 
3,054.3

 
1,099.6

 

 
1,954.7

 
1,099.6

Williston Basin
 
197.1

 
29.5

 
3.9

 
167.6

 
25.6

Uinta Basin
 
371.1

 
106.4

 
121.5

 
264.7

 
(15.1
)
Legacy
 
100.1

 
100.5

 
97.9

 
(0.4
)
 
2.6

Southern Region
 
 

 
 

 
 

 
 
 
 
Haynesville/Cotton Valley
 
8.5

 
8.4

 
5.5

 
0.1

 
2.9

Midcontinent
 
1,617.9

 
1,371.2

 
997.0

 
246.7

 
374.2

Total production
 
5,349.0

 
2,715.6

 
1,225.8

 
2,633.4

 
1,489.8

 
A summary of natural gas equivalent total production by major geographical area is shown in the following table:
 
 
Year ended December 31,
 
Change
 
 
2012
 
2011
 
2010
 
2012 vs. 2011
 
2011 vs. 2010
QEP Energy - Total Production (Bcfe)
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
Pinedale
 
99.7

 
79.4

 
68.5

 
20.3

 
10.9

Williston Basin
 
20.3

 
7.1

 
2.9

 
13.2

 
4.2

Uinta Basin
 
23.9

 
20.8

 
21.4

 
3.1

 
(0.6
)
Legacy
 
13.7

 
14.2

 
15.8

 
(0.5
)
 
(1.6
)
Southern Region
 
 

 
 

 
 
 
 
 
 
Haynesville/Cotton Valley
 
112.3

 
107.5

 
79.8

 
4.8

 
27.7

Midcontinent
 
49.3

 
46.2

 
40.6

 
3.1

 
5.6

Total production
 
319.2

 
275.2

 
229.0

 
44.0

 
46.2

 
Northern Region

Pinedale
Net production from the Pinedale Anticline, located in western Wyoming, grew 26% to 99.7 Bcfe during 2012, compared to the year earlier. Net production from Pinedale grew 16% to 79.4 Bcfe during 2011, compared to a year earlier. Pinedale production growth in 2012 and 2011 was driven by increased drilling activity over that period and the fee-based processing agreement at Blacks Fork II entered into in the third quarter of 2011 between QEP Energy and QEP Field Services. As a result of the processing agreement, QEP Energy's NGL production at Pinedale during 2012, was 3,054.3 Mbbl, contrasted with 1,099.6

30



Mbbl in the comparable 2011 period. During the years ended December 31, 2012, 2011 and 2010, Pinedale's production represented 31%, 29% and 30% of QEP Energy's total production, respectively.

Williston Basin
In the Williston Basin, production increased 186% to 20.3 Bcfe during 2012, from the year earlier, and increased 145% during 2011, compared to 2010, due to increased oil-directed drilling activity in the basin. In addition, the 2012 Acquisition contributed 5.2 Bcfe of increased production in the fourth quarter 2012. During the years ended December 31, 2012, 2011 and 2010, Williston Basin production represented 6%, 3% and 1% of QEP Energy's total production, respectively.

Uinta Basin
In the Uinta Basin, which is located in eastern Utah, production increased 15% to 23.9 Bcfe during 2012 due to increased drilling activity in the Lower Mesaverde formation in the Red Wash Unit. NGL production increased 264.7 Mbbl during 2012 compared to 2011, primarily as a result of QEP Energy executing a cryogenic, fee-based processing agreement with QEP Field Services for a portion of the Red Wash Unit's natural gas production in mid-2012. During 2011, production decreased 3% from decreased drilling activity, despite a first quarter 2011 prior-period adjustment of QEP's ownership interest within a federal unit participating area, which resulted in a positive adjustment to reported volumes of 1.6 Bcfe. During the years ended December 31, 2012, 2011 and 2010, Uinta Basin production represented 7%, 8%, and 9%, respectively, of QEP Energy's total production.

Legacy
QEP Energy's Legacy properties include all Northern Region Rockies properties except those at Pinedale, the Williston Basin and the Uinta Basin. Legacy's net production during 2012, decreased 4% to 13.7 Bcfe and decreased 10% during the year ended December 31, 2011. The decreased production was primarily due to declining production on older wells partially offset by drilling activity in the Powder River Basin. During both the years ended December 31, 2012 and 2011, Legacy's production represented 4% of QEP Energy's total production and 7% during the year ended December 31, 2010.

Southern Region

Haynesville/Cotton Valley
Net production from the Haynesville Shale and Cotton Valley's tight sand gas plays in northwest Louisiana increased 4% to 112.3 Bcfe during 2012 when compared to 2011. The increase in 2012 was due to the completion of several high-rate wells in early 2012 that were drilled during the latter half of 2011. QEP Energy has discontinued operated development drilling in the Haynesville Shale and Cotton Valley's tight sand gas plays in response to depressed natural gas prices. QEP Energy expects production from the Haynesville/Cotton Valley to continue to decline from its peak in the second quarter of 2012 as the last operated rig was released in July 2012. In addition, the completion of five wells that were drilled and cased in 2012 were completed in January 2013. Net production in the Haynesville/Cotton Valley area grew 35% to 107.5 Bcfe during 2011 compared to 2010, due to the Company's active drilling in the play in 2011. During the years ended December 31, 2012, 2011 and 2010, Haynesville/Cotton Valley's production comprised 35%, 39% and 35% of QEP Energy's total production, respectively.

Midcontinent
Net production in the Midcontinent grew 7% to 49.3 Bcfe during 2012 compared to 2011, driven by a 65% increase in crude oil production and an 18% increase in NGL production. Net production in the Midcontinent grew 14% to 46.2 Bcfe during 2011 compared to 2010. Midcontinent production growth in 2012 and 2011 was driven by the continued development of the Granite Wash, Marmaton and Tonkawa plays in Texas and western Oklahoma and the Woodford "Cana" Shale liquids-rich gas play in the Anadarko Basin of western Oklahoma. During the years ended December 31, 2012, 2011 and 2010, Midcontinent's production represented 15%, 17% and 18% of QEP Energy's total production, respectively.

31




Productive Wells
The following table summarizes the Company's productive wells as of December 31, 2012, all of which are located in the U.S.:
 
 
Natural gas
 
Oil
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
Pinedale
 
715

 
450

 

 

 
715

 
450

Williston Basin
 

 

 
263

 
108

 
263

 
108

Uinta Basin
 
685

 
497

 
1,771

 
209

 
2,456

 
706

Legacy
 
787

 
248

 
381

 
133

 
1,168

 
381

Southern Region
 
 
 
 
 
 
 
 
 
 
 
 
Haynesville/Cotton Valley
 
815

 
469

 
1

 

 
816

 
469

Midcontinent
 
2,522

 
763

 
429

 
98

 
2,951

 
861

Total productive wells
 
5,524

 
2,427

 
2,845

 
548

 
8,369

 
2,975

 
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 December 31, 2012, the Company had 77 gross wells with completions in more than one reservoir.
 
The Company also holds numerous overriding royalty interests in oil and gas wells, a portion of which are convertible to working interests after recovery of certain costs by third parties. Once the overriding royalty interest are converted to working interests, these wells are included in the Company's gross and net well count.
 

32



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, 2012. "Undeveloped Acreage" includes leasehold interests that already may have been classified as containing proved undeveloped reserves and unleased mineral interest acreage owned by the Company. Excluded from the table is acreage in which the Company's interest is limited to royalty, overriding royalty and other similar interests. All leasehold acres are located in the U.S.
 
 
Developed Acres (1)
 
Undeveloped Acres (2)
 
Total Acres
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
Colorado
 
158,865

 
106,062

 
103,455

 
30,624

 
262,320

 
136,686

Montana
 
33,245

 
10,776

 
343,606

 
62,764

 
376,851

 
73,540

New Mexico
 
94,169

 
66,433

 
34,689

 
12,714

 
128,858

 
79,147

North Dakota
 
97,222

 
42,523

 
214,232

 
85,834

 
311,454

 
128,357

South Dakota
 
40

 
40

 
204,798

 
107,551

 
204,838

 
107,591

Wyoming
 
272,964

 
159,598

 
351,361

 
247,842

 
624,325

 
407,440

Utah
 
191,247

 
147,772

 
221,511

 
140,107

 
412,758

 
287,879

Other
 
13,986

 
3,723

 
157,059

 
42,129

 
171,045

 
45,852

Southern Region
 
 
 
 
 
 
 
 
 

 

Arkansas
 
40,423

 
11,352

 
2,940

 
1,884

 
43,363

 
13,236

Kansas
 
32,224

 
13,368

 
52,379

 
17,205

 
84,603

 
30,573

Louisiana
 
79,652

 
65,103

 
2,205

 
2,165

 
81,857

 
67,268

Oklahoma
 
599,554

 
276,764

 
449,006

 
132,443

 
1,048,560

 
409,207

Texas
 
130,241

 
42,744

 
45,893

 
45,091

 
176,134

 
87,835

Other
 

 

 
1,757

 
1,300

 
1,757

 
1,300

Total
 
1,743,832

 
946,258

 
2,184,891

 
929,653

 
3,928,723

 
1,875,911

 ____________________________
(1) 
Developed acreage is leased 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.

Expiring Leaseholds
A portion of the leases summarized in the preceding table will expire at the end of their respective primary terms unless the leases are renewed or drilling or production has occurred on 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 undeveloped acres subject to leases summarized in the preceding table that will expire during the periods indicated: 
 
 
Undeveloped Acres Expiring
 
 
Gross
 
Net
Year ending December 31,
 
 
 
 
2013
 
107,088

 
62,324

2014
 
59,538

 
43,584

2015
 
90,924

 
72,145

2016
 
35,496

 
32,921

2017 and later
 
116,851

 
112,614

Total
 
409,897

 
323,588



33



Drilling Activity
The following table summarizes the number of development and exploratory wells drilled during the years indicated:
 
 
Developmental Wells
 
Exploratory Wells
 
 
Productive
 
Dry
 
Productive
 
Dry
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Year Ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pinedale
 
102.0

 
73.3

 

 

 

 

 

 

Williston Basin
 
88.0

 
28.0

 

 

 

 

 

 

Uinta Basin
 
254.0

 
45.1

 

 

 
1.0

 
0.6

 

 

Legacy
 
31.0

 
6.6

 

 

 

 

 

 

Southern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haynesville/Cotton Valley
 
35.0

 
15.7

 

 

 
2.0

 
1.6

 

 

Midcontinent
 
157.0

 
32.2

 

 

 

 

 

 

Total
 
667.0

 
200.9

 

 

 
3.0

 
2.2

 

 

Year Ended December 31, 2011
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Northern Region
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Pinedale
 
105.0

 
71.6

 

 

 

 

 

 

Uinta Basin
 
176.0

 
6.3

 

 

 

 

 

 

Legacy (1)
 
85.0

 
22.5

 

 

 

 

 

 

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

Total
 
678.0

 
176.7

 

 

 
6.0

 
1.7

 
6.0

 
2.6

Year Ended December 31, 2010
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Northern Region
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Pinedale
 
103.0

 
72.5

 

 

 

 

 

 

Uinta Basin
 
188.0

 
23.9

 

 

 

 

 

 

Legacy (1)
 
42.0

 
7.7

 

 

 

 

 
1.0

 
0.9

Southern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haynesville/Cotton Valley
 
85.0

 
44.0

 

 

 
33.0

 
16.2

 
1.0

 
1.0

Midcontinent
 
98.0

 
22.4

 

 

 

 

 

 

Total
 
516.0

 
170.5

 

 

 
33.0

 
16.2

 
2.0

 
1.9

 ____________________________
(1) 
Due to the 2012 Acquisition, the Company began breaking out the results of Williston Basin from Legacy in 2012. The Legacy well totals for the years ended December 31, 2011 and 2010, include the total development and exploratory wells drilled in the Williston Basin.


34



The following table presents operated and non-operated well completions for the year ended December 31, 2012:
 
Operated Completions
 
Non-operated Completions
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
Pinedale
102

 
73.3

 

 

Williston Basin
28

 
24.2

 
60

 
3.9

Uinta Basin
48

 
45.2

 
207

 
0.5

Legacy
7

 
4.6

 
24

 
2.0

 
 
 
 
 
 
 
 
Southern Region
 

 
 

 
 

 
 

Haynesville/Cotton Valley
29

 
16.5

 
8

 
0.8

Midcontinent
26

 
20.4

 
131

 
11.8


The following table presents operated and non-operated wells drilling and waiting on completion at December 31, 2012:
 
Operated
 
Non-operated
 
Drilling
 
Waiting on completion
 
Drilling
 
Waiting on completion
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pinedale (1)
2

 
2.0

 
63

 
45.9

 

 

 

 

Williston Basin
11

 
9.4

 
9

 
8.0

 
16

 
1.1

 
23

 
0.8

Uinta Basin
8

 
8.0

 
3

 
3.0

 

 

 

 

Legacy

 

 

 

 
6

 
0.2

 

 

Southern Region
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Haynesville/Cotton Valley

 

 
5

 
2.4

 

 

 

 

Midcontinent
3

 
2.1

 
10

 
8.8

 
6

 
0.5

 
35

 
1.6

____________________________
(1) 
QEP suspends Pinedale completion operations during the coldest months of the winter, generally from December to mid-March.

Delivery Commitments
The Company sells NGL under a term sales agreement that contains a delivery commitment for 8,500 barrels per day of NGL extracted at 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)
2013
164.7

2014
54.8

2015
29.8

 
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

35



commitments. See also Item 7 "Contractual Cash Obligations and Other Commitments" for discussion of firm transportation and storage commitments related to natural gas deliveries.
 
In addition, none of the Company's production from QEP Energy's 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 Item 1A - Risk Factors, in this Annual Report on Form 10-K.

Midstream Field Services – QEP Field Services
 
QEP Field Services owns 1,950 miles of gathering lines in Utah, Wyoming, Colorado, Louisiana and North Dakota. At December 31, 2012, QEP Field Services owns six processing plants, which extract NGL from the natural gas stream and have an aggregate capacity of 1.37 Bcf per day of unprocessed natural gas. In addition, QEP Field Services owns treating facilities in northwest Louisiana which remove impurities from the natural gas stream and have an aggregate 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. QEP Field Services Company owns a 60 mile crude oil pipeline regulated by FERC under the ICA.
 
In February 2013, QEP Field Services put into service the 150 MMcf per day cryogenic Iron Horse II processing plant, an expansion of its Stagecoach and Iron Horse processing complex in the Uinta Basin of eastern Utah. The plant predominantly provides fee-based processing services to third parties and affiliates.

Energy Marketing – QEP Marketing
 
QEP Marketing 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 a defendant in a number of lawsuits and is involved in governmental proceedings and regulatory controls arising in the ordinary course of business. QEP is also subject to various environmental-remediation and reclamation obligations arising from federal, state, and local laws and regulations. While the ultimate outcome and impact on QEP cannot be predicted with certainty,  except as discussed below, management does not believe that the resolution of pending proceedings will materially affect the Company's consolidated financial position, results of operations, or cash flows.

Chieftain Royalty Company v. QEP Energy Company, Case No CJ2011-1, U. S. District Court for the Western District of Oklahoma. This statewide class action was filed on January 20, 2011, on behalf of QEP's Oklahoma royalty owners asserting various claims for damages related to royalty valuation on all of QEP's Oklahoma wells operated by QEP or from which QEP marketed gas. Claims included breach of contract, breach of fiduciary duty, fraud, unjust enrichment, tortious breach of contract, conspiracy, and conversion, based generally on asserted improper deduction of post-production costs. The Court certified the class as to the breach of contract, breach of fiduciary duty and unjust enrichment claims. The parties successfully mediated the case in January 2013. On February 13, 2013, the parties executed a Stipulation and Agreement of Settlement (the Chieftain Settlement Agreement) providing for a cash payment from QEP to the class in the amount of $115.0 million, payable into an escrow account within five business days following the Court's preliminary approval of the settlement. In consideration for the settlement payment, QEP will receive a full release of all claims regarding the calculation, reporting and payment of royalties from the sale of natural gas and its constituents for all periods prior to February 28, 2013, and all class members are enjoined from asserting claims related to such royalties. As part of the Chieftain Settlement Agreement, the parties also agreed on the methodology for the calculation and payment of future royalties payable by QEP, or its successors and assigns, under all class leases for the life of such leases. The Court has entered a Preliminary Order Approving Class Action Settlement.

Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services' former affiliate Questar Gas Company (QGC) filed this complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract and breach of implied covenant of good faith and fair dealing, for an accounting and declaratory judgment related to a 1993 gathering agreement (1993 Agreement) entered into when the parties were affiliates.

36



Under the 1993 Agreement, QEP Field Services provides gathering services for producing properties developed by former affiliate Wexpro Company on behalf of QGC's utility ratepayers. The core dispute pertains to the annual calculation of the gathering rate, which is based on a cost of service concept expressed in the 1993 Agreement and in a 1998 amendment. The annual gathering rate has been calculated in the same manner under the contract since it was amended in 1998, without any prior objection or challenge by QGC. Specific monetary damages are not asserted. Also, on May 1, 2012, QEP Field Services Company filed a legal action against QGC entitled QEP Field Services Company v. Questar Gas Company, in the Second District Court in Denver County, Colorado, seeking declaratory judgment relating to its gathering service and charges under the same agreement.

In October 2009, the Company received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from unpermitted work resulting in the discharge of dredged and/or fill material into waters of the United States at three sites located in Caddo and Red River Parishes, Louisiana. EPA Region 6 has assumed lead responsibility for enforcement of the cease and desist order and any possible future orders for the removal of unauthorized fills and/or civil penalties under the Clean Water Act. In 2012, the Company completed a field audit, which identified 112 additional instances affecting approximately 90 acres where work may have been conducted in violation of the Clean Water Act. The Company has disclosed each of these instances to the EPA under the EPA's Audit Policy (to reduce penalties) and to the COE. The Company is working with the EPA and the COE to resolve these matters, which will require the Company to undertake certain mitigation and permitting activities, and may require the Company to pay a monetary penalty. At this time, QEP is unable to estimate the potential loss related to this matter, but believes it exceeds the $100,000 threshold for disclosure of environmental matters.

See also Note 9 (Commitments and Contingencies) to the consolidated financial statements in Item 8 of Part II of this Annual Report.

ITEM 4. MINE SAFETY DISCLOSURES
 
Not applicable.

37




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, 2013, QEP had 7,260 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 Company's Board of Directors. The Company expects that cash dividends will continue to be paid in the future.

The following table 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)
2012
 
 
 
 
 
 
First quarter
 
$
35.61

 
$
26.73

 
$
0.02

Second quarter
 
32.03

 
24.35

 
0.02

Third quarter
 
33.50

 
26.12

 
0.02

Fourth quarter
 
32.92

 
25.99

 
0.02

Total
 
 

 
 

 
$
0.08

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

Total
 
 

 
 

 
$
0.08

 
Stock Performance Graph

The following stock performance information in this Item 5 of this Annual Report on Form 10-K is not deemed to be "soliciting material" or to be "filed" with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent QEP specifically incorporate it by reference into such a filing.
 
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's 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. 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.


38



 
 
Recent Sales of Unregistered Securities; Purchases of Equity Securities by QEP and Affiliated Purchasers
 
QEP had no unregistered sales of securities, or purchases of equity securities by QEP or affiliated purchasers, during the fourth quarter of 2012.


39



ITEM 6. SELECTED FINANCIAL DATA
 
Selected financial data for the five years ended December 31, 2012, is provided in the table below. Refer to Item 7 and Item 8 in Part II of this Annual Report on Form 10-k for discussion of facts affecting the comparability of the Company's financial data.
 
 
 
Year Ended December 31,
 
 
2012
 
2011
 
2010
 
2009
 
2008
 
 
(in millions, except per share information)
Results of Operations (1)
 
 
 
 
 
 
 
 
 
 
Revenues (2)
 
$
2,349.8

 
$
3,159.2

 
$
2,300.6

 
$
2,011.2

 
$
2,360.9

Operating (loss) income