QEP-2014.12.31-10K


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, 2014
 
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 800, 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. Yes ý No ¨
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, 2014): $6,213,156,302.
 
At January 31, 2015, there were 175,549,934 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 2015 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 U.S. Securities and Exchange Commission (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 Securities Exchange Act of 1934 (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 800, 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 (the Securities Act), and Section 21E of the Exchange Act. 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:

impact of the sale of QEP Field Services Company's midstream business;
ability to deliver continued growth by focusing on exploration and production assets;
compliance with governmental regulations;
risks associated with hydraulic fracturing;
maintaining leasehold inventory by drilling;
adequacy of insurance;
timing and impact of proposed environmental legislation and studies;
strong liquidity position providing financial flexibility;
adequacy of the Company's production and reserves to meet term sales commitments;
ability to purchase gas to satisfy delivery commitments;
ability to pursue acquisition opportunities;
fair value and critical accounting estimates;
plans to recover or reject ethane from produced natural gas;
QEP’s growth strategies;
impact of lower or higher commodity prices and interest rates;
impact of global geopolitical and macroeconomic events;
plans to enter into derivative contracts and managing counterparty risk;
plans to drill or participate in wells;
results from planned drilling operations and production operations;
pro forma results for acquired properties;
the Company's liquidity and sufficiency of cash flow from operations, cash-on-hand and availability under its credit facility to fund the Company's planned capital expenditures and operating expenses;
plans to divest of non-core assets;
expected gain or loss on sale of assets;
factors impacting oil, gas and NGL prices;
seasonality of QEP's operating results;

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assumptions regarding equity compensation;
ability to realize income tax benefits;
recognition of compensation costs related to equity compensation grants;
obligations under drilling contracts;
amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
the outcome of contingencies such as legal proceedings;
estimated accrual for loss contingencies and other items and likelihood that indemnification obligations will be satisfied;
financial impact of operational hazards;
future expenses and operating costs;
the amount, type and timing of derivative contracts and unrealized derivative gains and losses;
impact of nonperformance by trade creditors or joint venture partners;
adequacy of credit review procedures, loss reserves, customer deposits and collection procedures to protect against credit related issues;
the Company's credit rating;
loss of any large customer and the ability of the Company to replace customers;
expected contributions to the Company’s pension plans and returns from plan assets;
expected savings from service providers;
the importance of Adjusted EBITDA (a non-GAAP financial measure) as a measure of performance;
delays caused by transportation and refining capacity issues;
payment of dividends;
considerations regarding the standardized measure of future net cash flows relating to proved reserves;
potential for future asset impairments and impact of impairments on financial statements; and
factors impacting the timing and amount of share repurchases.

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 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, processing and refining capacity;
QEP's ability to successfully integrate acquired assets or divest of non-core assets;
the outcome of contingencies such as legal proceedings;
permitting delays;
operating risks such as unexpected drilling conditions;
weather conditions;
the availability and cost of debt and equity financing;
changes in laws or regulations;
legislation regarding climate change and other initiatives related to drilling and completion techniques, including hydraulic fracturing;
derivative activities;
volatility in the commodity-futures market;
substantial liabilities from legal proceedings and environmental claims;
failure of internal controls and procedures;
failure of QEP's information technology infrastructure or applications;
elimination of federal income tax deductions for oil and gas exploration and development costs;
regulatory approvals and compliance with contractual obligations;
actions, or inaction, by federal, state, local or tribal governments;
lack of, or disruptions in, adequate and reliable transportation for QEP's production;
competitive conditions;
production levels;

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reserve levels; 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 Company's 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 A non-GAAP financial measure which management defines as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA), adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment, and certain other non-cash and/or non-recurring items.
 
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 Natural gas processing method to extract NGL from natural gas by reducing the gas temperature to 100 degrees below zero Fahrenheit.

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 210.4-10(a)(6).
 
development well A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. See 17 C.F.R. Section 210.4-10(a)(9).

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 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. See 17 C.F.R. Section 210.4-10(a)(13).

FERC The Federal Energy Regulatory Commission.

GAAP Accounting principles generally accepted in the United States of America.
 
gas All references to "gas" in this report refer to natural gas.
 
gross "Gross" oil and gas wells or "gross" acres are the total number of wells or acres in which the Company has an ownership interest.
 
ICE Brent Brent crude oil traded on the Intercontinental Exchange, Inc. (ICE).

IFNPCR Inside FERC's Gas Market Report monthly settlement index for the Northwest Pipeline Corporation Rocky Mountains.
 

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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.

LLS The price of Louisiana Light Sweet crude oil on the New York Mercantile Exchange.

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" oil and gas wells or "net" acres are determined by the sum of the fractional ownership interest the Company has in the gross wells or acres.
 
NYMEX The New York Mercantile Exchange.

NYMEX HH The New York Mercantile Exchange price of natural gas at the Henry Hub. 

NYMEX WTI The New York Mercantile Exchange price of West Texas Intermediate crude oil.

oil All references to "oil" in this report refer to crude oil.

possible reserves Those additional reserves that are less certain to be recovered than probable reserves. See 17 C.F.R Section 210.4-10(a)(17).

probable reserves 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. See 17 C.F.R. Section 210.4-10(a)(18).
 
proved properties Properties with proved reserves. See 17 C.F.R. Section 210.4-10(a)(23).

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 prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. See 17 C.F.R. Section 210.4-10(a)(22).
 
reserves Estimated remaining quantities of natural gas, crude oil and related substances anticipated to be economically producible as of a given date 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 or a revenue interest in the production. See 17 C.F.R. Section 210.4-10(a)(26).
 
reservoir A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. See 17 C.F.R. Section 210.4-10(a)(27).

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

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

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owner of the minerals at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
 
seismic data 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 210.4-10(a)(31).
 
working interest An interest in an oil and gas lease that gives the owner the right to drill, produce and conduct operating activities on the leased acreage and receive a share of any production, subject to all royalties, other burdens and to all capital costs and operating expenses.



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FORM 10-K
ANNUAL REPORT 2014
PART I
ITEM 1. BUSINESS

Nature of Business
 
QEP Resources, Inc. (QEP or the Company) is a holding company with two subsidiaries, QEP Energy Company and QEP Marketing Company, which are engaged in two primary lines of business: (i) oil and gas exploration and production (QEP Energy) and (ii) oil and gas marketing, operation of the Haynesville Gathering System and an underground gas storage facility (QEP Marketing and Other). See Part II, Item 8 - Financial Statements and Supplementary Data, Note 14 - Operations by Line of Business, of the Notes to the Consolidated Financial Statements for financial information relating to our segments.

QEP's operations are focused in two geographic regions: the Northern Region (primarily in Wyoming, North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana) of the United States. QEP's corporate headquarters are located in Denver, Colorado.

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 (the 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.

Discontinued Operations

In October 2014, the Company announced that its wholly owned subsidiary, QEP Field Services Company (QEP Field Services), had entered into a definitive agreement to sell substantially all of its midstream business, including the Company's ownership interest in QEP Midstream Partners, LP (QEP Midstream), to Tesoro Logistics LP (Tesoro). On December 2, 2014, QEP closed the sale of its midstream business to Tesoro (Midstream Sale) for total cash proceeds of $2.5 billion, including $230.0 million to refinance debt at QEP Midstream, subject to post-closing adjustments, and QEP recorded a pre-tax gain of $1.8 billion on its Consolidated Statements of Operations in "Net income from discontinued operations, net of income tax" for the year ended December 31, 2014. The decision to sell the midstream business was the result of the Company’s ongoing review of strategic alternatives to maximize shareholder value. QEP Marketing retained ownership of the Haynesville Gathering System. As a result of the Midstream Sale, the QEP Field Services reporting segment, excluding the retained ownership of the Haynesville Gathering System, has been classified as a discontinued operation on the Consolidated Statement of Operations and the Notes accompanying the Consolidated Financial Statements. For reporting purposes, the retained Haynesville Gathering System has been combined with QEP Marketing and Other.

Financial and Operating Highlights

Our financial and operating highlights for 2014 are as follows:
Incurred a net loss from continuing operations of $409.5 million, or $2.28 per diluted share, a decrease of $461.6 million from the net income from continuing operations of $52.1 million, or $0.29 per diluted share, in 2013;
Generated Adjusted EBITDA from continuing operations (a non-GAAP financial measure defined and reconciled in Item 7 of Part II of this Annual Report on Form 10-K) of $1,438.3 million, up from $1,316.0 million in 2013;
Increased liquids (oil and NGL) production by 59% to 143.4 Bcfe;
Increased liquid (oil and NGL) proved reserves by 7% to 1.6 Tcfe;
Added 294.1 Bcfe of proved reserves from extensions and discoveries;
Completed the Midstream Sale for approximately $2.5 billion, including $230.0 million to refinance debt at QEP Midstream, resulting in a pre-tax gain on sale of approximately $1.8 billion;
Completed the acquisition of oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $941.8 million; and

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Completed sales of non-core oil and gas properties for aggregate proceeds of $787.8 million, resulting in a pre-tax loss of $146.1 million.

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

operate in a safe and environmentally responsible manner;
allocate capital to those projects that generate the highest 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;
actively market our production to maximize value;
utilize derivative contracts to mitigate the impact of gas, oil or NGL price volatility and fluctuating interest rates, while locking in acceptable cash flows required to support future capital expenditures;
attract and retain the best people; and
maintain a capital structure that provides us the necessary financial flexibility with which to invest in organic growth and potential acquisition opportunities, as they may arise.

On December 2, 2014, QEP completed the Midstream Sale; see "Discontinued Operations" above. QEP believes this decision represents a significant milestone in the strategic repositioning of the Company, as it will be better positioned to deliver continued growth by focusing on its exploration and production assets.

Exploration and Production – QEP Energy
 
QEP Energy conducts exploration and production (E&P) activities in several of North America's most important hydrocarbon resource plays. QEP Energy has an inventory of identified development drilling locations, primarily in the Pinedale Anticline in western Wyoming, the Williston Basin in North Dakota, the Uinta Basin in eastern Utah, the Permian Basin in western Texas, the Haynesville/Cotton Valley in northwestern Louisiana, and other proven properties in Wyoming, Utah and Colorado. During 2013 and 2014, QEP sold the majority of its former properties within its Midcontinent area located in the Anadarko Basin in Oklahoma and Texas.

On February 25, 2014, QEP Energy acquired oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $941.8 million (the Permian Basin Acquisition). The acquired properties consist of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 270 vertical producing wells in the Permian Basin, which creates a new core area of operation for QEP Energy. Additionally, 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 (the Williston Basin Acquisition).

The following map illustrates the location of the Company's significant E&P activities, its Northern and Southern Regions described elsewhere in this report, and related reserve and production data as of December 31, 2014:

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QEP Energy generated approximately $1,437.0 million, $1,301.8 million, and $1,118.4 million of the Company's Adjusted EBITDA from continuing operations (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, 2014, 2013 and 2012, respectively. During 2014, QEP Energy operated in two core regions – the Northern Region (including the states of Wyoming, North Dakota, Utah and Colorado) and the Southern Region (including the states of Texas and Louisiana). The Northern Region contributed 71% of 2014 production, while the Southern Region contributed 29%. QEP Energy reported 3,931.9 Bcfe of estimated proved reserves as of December 31, 2014, down 130.0 Bcfe from 2013. Of those estimated proved reserves, approximately 77%, or 3,026.0 Bcfe, were located in the Northern Region at December 31, 2014, compared to 75%, or 3,039.7 Bcfe, at December 31, 2013. The remaining 23%, or 905.9 Bcfe, were located in the Southern Region at December 31, 2014, compared to 25%, or 1,022.2 Bcfe, at December 31, 2013. Approximately 56% of the total proved reserves reported by QEP Energy at December 31, 2014, were developed and approximately 41% of the total proved reserves were comprised of oil and NGL, up from 37% at December 31, 2013.

QEP Energy faces competition in every facet of its business, including the acquisition of producing leaseholds, wells, and undeveloped leaseholds, the marketing of oil and gas, and the procurement of goods, services and labor. Its longer-term growth strategy depends, in part, on its ability to acquire reasonably valued acreage containing undeveloped reserves and identify and develop the reserves in a responsible, low-cost and efficient manner.

QEP Energy seeks to acquire, develop and produce oil and gas from resource plays in its core operating areas and expand into new areas where it can capitalize on its operating expertise. Since the existence and distribution of hydrocarbons in resource plays is now better understood, developing these accumulations has lower risk than conventional discrete hydrocarbon accumulations. Resource plays typically require drilling many wells at high density to fully develop and recover the hydrocarbon accumulations. QEP Energy's resource play development requires expertise in drilling large numbers of complex,

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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 conducts some exploratory drilling to determine the commercial viability of its unproven leasehold inventory. For 2015, QEP plans to allocate approximately $960.0 million of its capital budget to E&P activities. QEP Energy seeks to maintain geographical and geological diversity with its two core regions. In addition to the Williston Basin Acquisition in 2012 and the Permian Basin Acquisition in 2014, the Company may pursue additional acquisitions of producing properties through the purchase of assets or corporate entities in order to further expand its presence in its core areas of operations or to create new core areas.
 
QEP Energy, both directly and through its affiliate, QEP Marketing, sells its gas, oil and NGL production to a variety of customers, including gas-marketing firms, industrial users, local-distribution companies, crude oil refiners and marketers. QEP Energy regularly evaluates counterparty credit risk and may require financial guarantees or prepayments from parties that fail to meet its credit criteria.

Energy Marketing — QEP Marketing and Other
 
QEP Marketing provides wholesale marketing and sales of affiliate and third-party gas, oil and NGL. The reporting segment QEP Marketing and Other generated $1.3 million, $14.2 million and $39.0 million of the Company's Adjusted EBITDA from continuing operations (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) for each of the years ended December 31, 2014, 2013 and 2012, respectively. 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 gas 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 sells NGL volumes associated with the gas stored in its Clear Creek storage facility. In addition, QEP Marketing owns and operates the Haynesville Gathering System, located in Louisiana. The Haynesville Gathering System includes 200 miles of gas gathering facilities with approximate throughput capacity of 2,000 MMcf/d and a treating facility with throughput capacity of 600 MMcf/d and primarily provides services to QEP Energy.
 
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 gas and volumes purchased from third parties to wholesale marketers, industrial end-users and utilities. QEP Marketing sells QEP Energy's oil volume to refiners, marketers and other companies, including some with pipeline facilities near QEP Energy's producing properties. In the event pipeline facilities are not available, QEP Marketing arranges transportation of 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 compliance, in all material respects, 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 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 Part I, Item 1A - Risk Factors, in this Annual Report on Form 10-K.

Regulation of Exploration and Production 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, but are not limited to, 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 in its business, including but not limited to engines, tanks and dehydrators.


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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) endanger 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 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 taken, or are considering, legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, GHG permitting and/or regional GHG cap and trade programs; however, some states have required or proposed direct regulation of GHG emissions from oil and gas facilities, including, for example, methane leak detection monitoring and repair for upstream oil and gas activities and best management practices for well liquids unloading activities.

The EPA is also considering direct regulation of methane emissions from oil and gas facilities. On January 14, 2015, the White House and the U.S. Environmental Protection Agency indicated that they plan to amend 40 C.F.R Part 60, Subpart OOOO (Subpart OOOO) standards to achieve additional methane and volatile organic compound reductions from the oil and natural gas industry. These potential amendments to Subpart OOOO could result in additional regulatory requirements and standards for completions of hydraulically fractured oil wells, pneumatic pumps, and leaks from new and modified oil and gas exploration, production, and gathering facilities. A proposed rule is expected in 2015, with a final rule expected in 2016.

Clean Water Act and Safe Drinking Water Act. The Clean Water Act and similar state laws regulate discharges of wastewater, oil, fill material and pollutants into waters of the U.S. (e.g., 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.

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 oil, 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 discloses 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. QEP also

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employs additional measures to protect water quality such as conducting baseline sampling for all new water wells, using hydrocarbon free lubricants in water well construction, locking all inactive water wells to prevent unauthorized use, and transporting both fresh and produced water by pipeline instead of truck when possible to avoid truck traffic and emissions. The Company believes that the employment of fracture stimulation technology does not present any significant additional risks other than the risks generally associated with oil and gas 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 oil and gas well design and operation. Additionally, in May 2012 the Bureau of Land Management (BLM) proposed new regulations regarding chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic fracturing, on federal and tribal land, and proposed revisions to those regulations in May 2013. Those proposed regulations are still pending with the BLM and are not final. 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 permitting 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 in 2015. Moreover, the EPA announced in October 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and plans to propose standards that such wastewater must meet before being transported to a publicly owned treatment plant. The EPA has also issued an advance notice of proposed rulemaking and initiated a public participation process under the Toxic Substances Control Act (TSCA) to seek comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanisms for obtaining this information. 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 SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing; and (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. Additionally, federal and state agencies are studying air quality impacts from hydraulic fracturing practices. These ongoing or proposed studies and investigations could spur initiatives to further regulate hydraulic fracturing under the SDWA, the Clean Air Act or other statutes and regulatory programs.

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 oil and gas operations on Native American tribal lands where 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.

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. On January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that the EPA 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

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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) 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 an exemption from these clearing and cash collateral requirements for commercial end-users. See Part I, Item 1A - Risk Factors, in this Annual Report on Form 10-K for more information.

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. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
 
Other Regulations. The U.S. Department of Transportation has started rulemaking to develop new requirements for shipping crude oil by rail.

State Regulations

North Dakota. The North Dakota Industrial Commission (the Commission), North Dakota's chief energy regulator, recently issued an order to reduce the volume of natural gas flared from oil wells in the Bakken and Three Forks formations. In addition, the Commission is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals. Based on the Company’s production forecasts and midstream agreements, QEP believes it is and will continue to be in compliance with this new order from the Commission.

On December 9, 2014, the Commission issued Commission Order No. 25417 requiring that crude oil produced in the Bakken Petroleum System be conditioned to remove lighter, volatile hydrocarbons to improve the marketability and safe transportation of the crude oil. The Commission's order is effective April 1, 2015. QEP believes it is currently in compliance with this new order from the Commission.

Regulation of Underground Storage
 
QEP, through its wholly owned subsidiary 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.

Seasonality

QEP's results of operations can be negatively impacted by the weather. In the Pinedale field, QEP typically ceases completion activities on newly drilled wells due to adverse weather conditions from approximately December to mid-March. In the Williston Basin, QEP drills and completes wells throughout the year, but adverse weather conditions can impact drilling and field operations.

Significant Customers

The Company's five largest customers accounted for 33%, 38%, and 27%, in the aggregate, of QEP's revenues for the years ended December 31, 2014, 2013 and 2012, respectively. Management believes that the loss of any of these customers, 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 year ended December 31, 2014, Valero Marketing and Supply Company accounted for 10% of the Company's total revenues. During the year ended December 31, 2013, Freepoint Commodities, LLC and Arrow Midstream Holdings, LLC accounted for 13% and 11%, respectively, of the Company's total revenues. During the year ended December 31, 2012, no customer accounted for 10% or more of QEP's total revenues.

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Employees
 
At December 31, 2014, QEP had 765 employees compared to 1,001 employees at December 31, 2013. None of QEP's employees are represented by unions or covered by collective bargaining agreements. The decrease in the number of employees from December 31, 2013 is primarily due to the Midstream Sale.

Executive Officers of the Registrant

The name, age, period of service, title and business experience of each of QEP's executive officers as of January 31, 2015, are listed below:
Charles B. Stanley
 
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Chairman (2012 to present). President and Chief Executive Officer (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
 
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Executive Vice President and Chief Financial Officer (2010 to present). Treasurer (2010 to 2014). Chief Accounting Officer (2013 to 2014). 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).
Jim E. Torgerson
 
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Executive Vice President (2013 to Present). Senior Vice President - Operations (2012 to 2013). 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).
Austin S. Murr
 
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Senior Vice President - 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).
Abigail L. Jones
 
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Vice President, Compliance and Corporate Secretary (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
 
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Vice President and General Counsel (2012 to present). 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 D. 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), including Director of Human Resources.

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 any of the officers were selected.

ITEM 1A. RISK FACTORS
 
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. 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 on Form 10-K actually occur, the Company's business, financial condition or results of operations could be materially adversely affected.
 
The prices for gas, oil and NGL are volatile, and the recent decline in such prices could adversely affect QEP's results, stock price and growth plans. Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil, natural gas, and NGL production. Historically gas, oil and NGL prices have been volatile and will likely continue to be volatile in the future. Crude oil prices are influenced by a variety of factors, including global supply and demand, currency values, geopolitical dynamics and other factors. U.S. natural gas prices in particular are significantly influenced by weather and weather forecasts as well as supply and demand. NGL prices generally move in sympathy with natural gas and crude oil prices as well as react to demand for the individual components that make up NGLs. 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 or 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.

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QEP cannot predict the future price of gas, oil and NGL because of factors beyond its control, including but not limited to:
 
changes in domestic and foreign supply of gas, oil and NGL;
the potential long-term impact of an abundance of gas, oil and NGL from unconventional sources on the global and local energy supply;
changes in local, regional, national and global demand for gas, oil, NGL and related commodities;
the level of imports and/or exports of, and the price of, foreign gas, oil and NGL;
localized supply and demand fundamentals, including the proximity, cost and availability of pipelines and other transportation facilities, and other factors that result in differentials to benchmark prices from time to time;
the availability of refining capacity;
domestic and global economic conditions;
speculative trading in crude oil and natural gas derivative contracts;
the continued threat of terrorism and the impact of military and other action;
the activities of the Organization of Petroleum Exporting Countries (OPEC), including the ability of members of OPEC to agree to and maintain oil price and production controls;
political and economic conditions in the United States and in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;
the impact of U.S. dollar exchange rates on oil, NGL and natural gas prices;
weather conditions, weather forecasts and natural disasters;
government regulations and taxes, including regulations or legislation relating to climate change or oil and gas 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;
the level of global oil, gas and NGL inventories and exploration and production activity;
exports from the United States of oil, NGL and natural gas; and
the quality of oil and gas produced.

During the last quarter of 2014, the prices of oil and natural gas decreased due to an over-supply and decreasing demand. As a result of the current supply and demand fundamentals, the prices of oil and natural gas may stay suppressed for some time compared to the price levels experienced during the last few years. In response to significantly lower commodity prices, we have reduced planned drilling activities and planned capital expenditures, as have many other oil and gas producers. As a result of lower industry activity, we have secured cost decreases from many service providers and expect additional savings going forward. If commodity prices stay depressed or decline further, this could reduce our cash flow from operations and cause us to alter our business plans, including a further reduction or delay of exploration and development spending and other cost reduction initiatives.

Lower commodity prices, such as those experienced recently, may not only decrease our revenues and cash flows but also may reduce the amount of gas, oil and NGL that we can produce economically. In addition, lower commodity prices may result in additional asset impairment charges from reductions in the carrying values of QEP's oil and gas properties. During the years ended December 31, 2014, 2013 and 2012, QEP recorded impairment charges of $1,041.4 million, $1.2 million and $107.6 million, respectively, on its proven properties and $101.8 million, $32.3 million and $25.4 million, respectively, on its unproven properties. During the year ended December 31, 2013, QEP also recorded goodwill impairment of $59.5 million. Forward prices have continued to decline subsequent to the measurement of impairment at December 31, 2014. If commodity prices decline further during 2015, there could be additional impairment charges to our oil and gas assets or other investments. 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 the 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 growth rate is achieved. Historically, global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate is likely to result in more modest or decreased demand growth for QEP's 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 gas, oil and NGL, but also on its ability to find, develop and acquire oil and gas reserves that are economically recoverable. Producing oil and gas reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics. Because oil and gas 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 oil and gas reserves to replace those depleted by production.
 
Oil and gas reserve estimates are imprecise and subject to revision. QEP's proved oil and gas reserve estimates are prepared annually by independent reservoir engineering consultants. Oil and gas 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 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 on Form 10-K is reflective of the current market value of the estimated oil and gas 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 oil and gas 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 oil and gas prices. Decreases in the costs of these services typically lag declines in oil and natural gas prices.

QEP's operations are subject to operational hazards and unforeseen interruptions for which QEP may not be adequately insured. There are operational risks associated with the exploration, production, gathering, transporting, and storage of oil, natural gas and NGLs, including:
 
injuries and/or deaths of employees, supplier personnel, or other individuals;
fire, explosions and blowouts;
aging infrastructure and mechanical problems;
unexpected drilling conditions, including abnormally pressured formations or loss of drilling fluid circulation;
pipe, cement or casing failures;
title problems;
equipment malfunctions and/or mechanical failure;
security breaches, cyberattacks, piracy, or terroristic acts;
theft or vandalism of oilfield equipment and supplies, especially in areas of increased activity;
severe weather that could affect QEP's operations;
plant, pipeline, railway and other facility accidents and failures;
truck and rail loading and unloading; and
environmental accidents such as oil spills, natural gas leaks, pipeline or tank ruptures, or discharges of air pollutants, brine water or well fluids into the environment.


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QEP 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, 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, QEP may also be exposed to the risks enumerated above from operations that are not within its care, custody or control.

Consistent with industry practice, QEP generally indemnifies 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 fault. Therefore, QEP may be liable, regardless of fault, 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 in addition to claims for personal injury or death suffered by QEP's employees and others. QEP's drilling contracts and oilfield service agreements, however, often provide that the contractor will indemnify QEP for claims related to injury and death of employees of the contractor and for property damage suffered by the contractor.

As is also customary in the oil and gas industry, QEP 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.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application. Our operations involve utilizing some of the latest drilling and completion techniques. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

landing our wellbore in the desired drilling zone;
staying in the desired drilling zone while drilling horizontally through the formation;
running our casing the entire length of the wellbore; and
being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing our wells include, but are not limited to, the following:

the ability to fracture stimulate the planned number of stages;
the ability to run tools the entire length of the wellbore during completion operations; and
the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

If our drilling and completion results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Multi-well pad drilling may result in volatility in QEP operating results. QEP utilizes multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in QEP’s quarterly operating results.

Lack of availability of refining, storage or transportation capacity will likely impact results of operations. The lack of availability of satisfactory oil, gas and NGL transportation, including trucks, railways and pipelines, storage or refining capacity may hinder QEP's access to oil, NGL and 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 transportation, storage or refineries 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, accidents or other reasons. If transportation or storage facilities do not exist near producing wells, if transportation, storage or refining capacity is limited or if transportation or refining capacity is unexpectedly disrupted, completion activity could be delayed, sales could be reduced, or production shut in each of which could reduce profitability. Furthermore, if QEP were required to shut in wells, it might also be obligated to pay certain demand charges for gathering and processing services, firm transportation charges on interstate pipelines as well as 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. In addition, rail accidents involving crude oil carriers have resulted in regulations, and may result in additional regulations, on transportation of oil by railway. If transportation quality requirements change, QEP might be required to install or contract for additional treating or processing equipment, which could increase costs. Federal and state regulation of oil and gas production and transportation, tax and energy

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policies, changes in supply and demand, transportation pressures, damage to or destruction of transportation facilities and general economic conditions could also adversely affect QEP's ability to transport oil and gas.

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 oil and gas 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, oil and gas 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.

QEP’s identified potential well locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, QEP may not be able to raise the substantial amount of capital that would be necessary to drill its potential well locations. QEP’s management team has specifically identified and scheduled certain well locations as an estimation of its future multi-year drilling activities on its existing acreage. These well locations represent a significant part of QEP’s growth strategy. QEP’s ability to drill and develop these locations depends on a number of uncertainties, including oil and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water and water disposal facilities, regulatory approvals and other factors. Because of these factors, QEP does not know if the numerous potential well locations QEP has identified will be drilled or if QEP will be able to produce oil and gas from these or any other potential well locations. In addition, any drilling activities QEP is able to conduct on these potential locations may not be successful or result in QEP’s ability to add additional proved reserves to its overall proved reserves or may result in a downward revision of its estimated proved reserves, which could have a material adverse effect on QEP’s future business and results of operations.

QEP is required to pay fees to its midstream service providers based on minimum volumes regardless of actual volume throughput. QEP has contracts with third-party service providers for transportation services with minimum volume delivery commitments. As of December 31, 2014, QEP’s aggregate long-term contractual obligation under these agreements was $978.3 million. QEP is obligated to pay fees on minimum volumes to service providers regardless of actual volume throughput, which fees could be significant and have a material adverse effect on its results of operations.

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 oil and gas 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 financing 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 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, which in turn could lead to a possible reduction in QEP's oil or gas production, reserves and 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 $2.2 billion at December 31, 2014. 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

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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 agreement governing QEP's revolving credit facility and the indentures covering QEP’s senior notes contain a number of covenants that impose constraints on the Company, including restrictions on QEP's ability to dispose of assets, make certain investments, incur liens and engage in transactions with affiliates.

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 counterparties. 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 opposition to 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 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 or gathering 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;
cyberattacks;
legal challenges or lawsuits;
negative publicity about QEP;
increased costs of doing business;
reduction in demand for QEP's products;
other adverse effects on QEP's ability to develop its properties and increase production;
regulation of rail transportation of crude oil; and
construction of new oil and gas transmission pipelines.

QEP may incur substantial costs associated with responding to these initiatives or complying with any resulting additional legal or regulatory requirements that are not adequately provided for and 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 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 margin 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 in QEP's income, which creates the risk of volatility in earnings even if no economic impact to QEP has occurred

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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.

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 oil and gas 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 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 oil and gas 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. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than QEP is able to offer. 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 Williston Basin Acquisition completed in September 2012 and its Permian Basin Acquisition completed in February 2014. QEP cannot provide assurance that it will be able to identify additional acquisition opportunities. Even if QEP does identify additional 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;
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.
 
In addition, QEP’s credit agreements and the indentures governing QEP’s senior notes impose certain limitations on QEP's ability to enter into mergers or combination transactions. QEP’s credit agreements also limit QEP’s ability to incur certain indebtedness, which could indirectly limit QEP’s ability to engage in acquisitions of businesses.

QEP may be unable to dispose of non-core, non-strategic assets on financially attractive terms, resulting in reduced cash proceeds. 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

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other factors. Inability to achieve a desired price for 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.

Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations. Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

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 satisfy 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 are evaluated 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.

New federal Clean Air Act regulations at 40 C.F.R Part 60, Subpart OOOO (Subpart OOOO) became effective in 2012, with further amendments effective in 2013 and 2014. Subpart OOOO imposes air quality controls and requirements upon QEP's operations and is undergoing further reconsideration by EPA, which may result in more stringent air quality controls and requirements for QEP’s operations. For example, on January 14, 2015, the White House and the U.S. Environmental Protection Agency indicated that they plan to amend the Subpart OOOO standards to achieve additional methane and volatile organic compound reductions from the oil and natural gas industry. These potential amendments to Subpart OOOO could result in additional regulatory requirements and standards for completions of hydraulically fractured oil wells, pneumatic pumps, and leaks from new and modified oil and gas exploration, production, and gathering facilities. A proposed rule is expected in 2015, with a final rule expected in 2016. Additionally, many states are adopting more stringent air permitting and other air quality control regulations specific to oil and gas exploration, production, gathering and processing that go beyond the requirements of federal regulations.


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On December 17, 2014, the EPA proposed to revise and lower the existing 75 parts per billion (ppb) national ambient air quality standard (NAAQS) for ozone under the federal Clean Air Act to a range within 65-70 ppb. EPA is also taking public comment on whether the ozone NAAQS should be revised as low as 60 ppb. A lowered ozone NAAQS in a range of 60-70 ppb could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which QEP operates. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.

FERC has jurisdiction over the operation of QEP Marketing's Clear Creek storage facility by virtue of the facility's connection 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 charged for transmission, open access/non-discrimination, and public disclosure via an electronic bulletin board of daily capacity and flows.

Requirements to reduce gas flaring could have an adverse effect on our operations. Wells in the Bakken and Three Forks formations in North Dakota, where we have significant operations, produce natural gas as well as crude oil. Constraints in the current gas gathering network in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. The North Dakota Industrial Commission, North Dakota's chief energy regulator, recently issued an order to reduce the volume of natural gas flared from oil wells in the Bakken and Three Forks formations. In addition, the Commission is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals. The Bureau of Land Management (BLM) has also indicated its intent to pursue a rulemaking related to further controlling the venting and flaring of natural gas on BLM land. These capture requirements, and any similar future obligations in North Dakota or our other locations, may increase our operational costs or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.

New rules regarding crude oil shipments by rail may pose unique hazards that may have an adverse effect on our operations. The U.S. Department of Transportation has started rulemaking to develop new requirements for shipping crude oil by rail. On December 9, 2014, the North Dakota Industrial Commission issued Commission Order No. 25417 requiring that crude oil produced in the Bakken Petroleum System be conditioned to remove lighter, volatile hydrocarbons to improve the marketability and safe transportation of the crude oil. The Commission’s order is effective April 1, 2015. These conditioning requirements, and any similar future obligations imposed at the state or federal level, may increase our operational costs or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate. Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material and adverse effect on our ability to develop and produce our reserves.
 
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. Many of QEP's operations are subject to the requirements of 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 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.


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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 2015 Budget Proposal and legislation introduced in a prior session of Congress includes proposals that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (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 any legislation as a result of these proposals 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 gas exploration and development, and any such change, as well as any changes to or the imposition of new state or local taxes (including the imposition of, or increase in production, severance or similar taxes), could increase the cost of exploration and development of oil and gas resources, which would negatively affect our financial condition and results of operations.

Environmental laws are complex and potentially burdensome for QEP's operations. QEP must comply with numerous and complex federal, state and tribal environmental 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 oil and gas 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. It may be costly and time consuming to comply with requirements imposed by these authorities, and compliance may result in delays in the commencement or continuation of the Company's exploration and production. For example, QEP's drilling operations on tribal lands within the Williston Basin in North Dakota and Vermillion Basin in Wyoming continue to be delayed due to substantial 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 oil and gas reserves. Currently, well construction activities, including hydraulic fracture stimulation, are regulated by state agencies that review and approve all aspects of oil and gas well design and operation. The EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the federal SDWA and issued guidance 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 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 lands and proposed further revision to those regulations in May 2013. 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.

The EPA is also considering other potential regulation of hydraulic fracturing activities. For example, the EPA is considering regulation of wastewater discharges from hydraulic fracturing and other natural gas production under the federal Clean Water Act. The EPA is also collecting information as part of a nationwide study into the effects of hydraulic fracturing on drinking water. The EPA issued a progress report regarding the study in December 2012, which described generally the continuing focus of the study, but did not provide any data, findings, or conclusions regarding the safety of hydraulic fracturing operations. The EPA intends to issue a final draft report for peer review and comment at the completion of the study. The results of this study, which is still ongoing, could result in additional regulations, which could lead to operational burdens similar to those described above. The EPA has also issued an advance notice of proposed rulemaking and initiated a public participation process under the Toxic Substances Control Act (TSCA) to seek comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances

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and mixtures and the mechanisms for obtaining this information. Additionally, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that the EPA 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. 
 
QEP's ability to produce oil and gas 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 or other waste 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 oil and gas requires the use and disposal of significant quantities of water. The availability of disposal wells with sufficient capacity to receive all of the water produced from QEP’s wells may affect QEP’s production. 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 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 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 oil and gas. QEP's ability to access and develop new oil and gas 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 and, as discussed above, is considering additional amendments to 40 C.F.R Part 60, Subpart OOOO to include additional requirements to reduce methane emissions from oil and natural gas facilities. In June 2014, the United States Supreme Court’s holding in Utility Air Regulatory Group v. EPA upheld a portion of EPA’s GHG stationary source permitting program, but also invalidated a portion of it. The Court held that stationary sources already subject to the Prevention of Significant Deterioration (PSD) or Title V permitting programs for non-GHG criteria pollutants remain subject to GHG Best Available Control Technology (BACT) and major source permitting requirements, but ruled that sources cannot be subject to the PSD or Title V major source permitting programs based solely on GHG emission levels. Upon remand, EPA is considering how to implement the Court’s decision. The Court’s holding does not prevent states from considering and adopting state-only major source permitting requirements based solely on GHG emission levels. In addition, in several of the states in which QEP operates the federal government is considering various GHG registration and reduction programs, including methane leak detection monitoring and repair requirements specific to oil and gas facilities. 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 Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), which was signed into law in July 2010, contains significant derivatives regulation, including a requirement that certain transactions be cleared on exchanges. The Act provides for an exception from these clearing requirements for commercial end-users, such as QEP. The Dodd-Frank Act may, however, require the posting of cash collateral for uncleared swaps and may limit trading in certain oil and gas related derivative contracts by imposing position limits. The rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on QEP’s business remains uncertain.

The Dodd-Frank Act and the rules promulgated thereunder could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks QEP encounters, reduce QEP’s ability to monetize or restructure QEP’s existing derivative contracts, increase the administrative burden and regulatory risk associated with entering into certain derivative contracts, and increase QEP’s exposure to less creditworthy counterparties. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and gas. QEP revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and its regulations is to lower commodity prices.

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Any of these consequences could affect the pricing of derivatives and make it more difficult for us to enter into derivative transactions, which could have a material and adverse effect on QEP’s business, financial condition and results of operations.

QEP relies on highly skilled personnel and, if QEP is unable to retain or motivate key personnel, hire qualified personnel, or transfer knowledge from retiring personnel, QEP’s operations may be negatively impacted. QEP’s performance largely depends on the talents and efforts of highly skilled individuals. QEP’s future success depends on its continuing ability to identify, hire, develop, motivate, and retain highly skilled personnel for all areas of its organization. Competition in the oil and gas industry for qualified employees is intense. QEP’s continued ability to compete effectively depends on its ability to attract new employees and to retain and motivate its existing employees. QEP does not have employment agreements with or maintain key-man insurance for its key management personnel. The loss of services of one or more of its key management personnel could have a negative impact on QEP’s financial condition and results of operations.

In certain areas of QEP’s business, institutional knowledge resides with employees who have many years of service. As these employees retire, QEP may not be able to replace them with employees of comparable knowledge and experience. QEP’s efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to QEP and could negatively impact QEP’s business.

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 oil and gas 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 62 active and suspended participants, or 8%, of QEP's active employees and 152 participants who are retired or were terminated and vested. QEP also sponsors an unfunded Supplemental Executive Retirement Plan. Over time, periods of declines in interest rates and pension asset values may result in a reduction in the funded status of the Company's pension plans. As of December 31, 2014 and 2013, QEP's pension plans were underfunded by $51.2 million and $46.3 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 $13.0 million and $11.5 million during the years ended December 31, 2014 and 2013, respectively, to its defined benefit pension plans and expects to make contributions of approximately $8.4 million to its pension plans in 2015. 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 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. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. QEP's technologies, systems, networks, and those of its vendors, suppliers and other business partners may become the target of cyberattacks 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. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We do not maintain specialized insurance for possible liability resulting from a cyberattack on our assets that may shut down all or part of our business.

ITEM 1B. UNRESOLVED STAFF COMMENTS
 
None.


26



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, North Dakota, Utah and Colorado) and the Southern Region (including the states of Texas and Louisiana).

Northern Region
 
Pinedale
QEP Energy's largest property, in terms of proved reserves, is Pinedale, where the Company is targeting the Lance Pool, which is a tight gas sand reservoir. The top of the Lance Pool reservoir ranges from 8,500 to 9,500 feet across QEP Energy's acreage. The Company currently estimates that there are up to 400 additional wells required to fully develop its Pinedale acreage on 5 to 10-acre density. On December 31, 2014, QEP Energy had four operated rigs drilling on the Pinedale Anticline. In addition to QEP Energy's 903 gross producing wells, QEP Energy has an overriding royalty interest in an additional 60 wells at Pinedale.
 
Williston Basin
QEP Energy has approximately 116,000 net acres in the Williston Basin in western North Dakota, where the Company is targeting the Bakken and Three Forks formations. The Company has been successful in lowering development well costs, de-risking unproven reserves, increasing production, increasing the number of future drilling locations and increasing its estimate of recoverable reserves. 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, 2014, QEP Energy had six operated rigs drilling in the Williston Basin.

Uinta Basin
The majority of the 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 232,000 net acres in the Uinta Basin. QEP Energy had one operated rig drilling in the Uinta Basin at December 31, 2014, targeting the Lower Mesaverde Formation productive fairway in which QEP Energy holds 32,300 net acres in the Red Wash Unit.
 
Other Northern
The remainder of QEP Energy's Northern Region leasehold interests and proved reserves are distributed over a number of fields and properties.

Southern Region
 
Permian Basin
QEP Energy has approximately 26,500 net acres of producing and undeveloped properties that were acquired through the Permian Basin Acquisition in the first quarter of 2014. The Company is targeting oil dominant zones from the Upper Spraberry formation down to the Atoka formation with a combination of horizontal and vertical wells. As of December 31, 2014, QEP Energy had six operated rigs drilling in the Permian Basin.

Haynesville/Cotton Valley
QEP Energy holds approximately 50,500 net acres of producing and undeveloped properties in the Haynesville Shale play in northwestern 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 deeper than the Hosston and Cotton Valley formations that QEP Energy has been developing in northwest Louisiana since the 1990's. As of December 31, 2014, QEP Energy did not have any operated rigs drilling in the Haynesville/Cotton Valley area, however, there were six gross non-operated wells drilling and 21 gross non-operated wells waiting on completion as of December 31, 2014.
 
Midcontinent
QEP Energy's Midcontinent operations cover all properties in the Southern Region except the Haynesville/Cotton Valley area of northwestern Louisiana and the Permian Basin properties in west Texas and are widely distributed. QEP sold the majority of its Midcontinent properties in 2014, including its properties in the Woodford "Cana" Shale in western Oklahoma, Granite Wash/Atoka Wash in the Texas panhandle and western Oklahoma and other non-core properties within this area. As of December 31, 2014, QEP Energy did not have any operated rigs drilling in the Midcontinent area.


27



Reserves – QEP Energy
 
At December 31, 2014 and 2013, approximately 93% and 89%, respectively, of QEP Energy's estimated proved reserves were Company operated. Proved developed reserves represented 56% and 53% of the Company's total proved reserves at December 31, 2014 and 2013, respectively, while the remaining reserves were classified as proved undeveloped. All reported reserves are located in the United States. QEP Energy does not have any long-term supply contracts with foreign governments, reserves of equity investees or reserves of subsidiaries with a significant minority interest. QEP Energy's estimated proved reserves are summarized in the table below:
 
 
December 31, 2014
 
December 31, 2013
 
 

 Gas
 
Oil
 
NGL
 
Total
 
 Gas
 
Oil
 
NGL
 
Total
 
 
(Bcf)
 
(MMbbl)
 
(MMbbl)
 
 (Bcfe)(1)
 
(Bcf)
 
(MMbbl)
 
(MMbbl)
 
 (Bcfe)(1)
Proved developed reserves
 
1,288.4

 
99.3

 
52.2

 
2,197.5

 
1,406.3

 
71.8

 
52.8

 
2,154.0

Proved undeveloped reserves
 
1,028.8

 
73.2

 
44.4

 
1,734.4

 
1,148.6

 
76.8

 
49.8

 
1,907.9

Total proved reserves
 
2,317.2

 
172.5

 
96.6

 
3,931.9

 
2,554.9

 
148.6

 
102.6

 
4,061.9

 ____________________________
(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, 2012, through December 31, 2014, are summarized in the table below:
Year Ended
December 31,
 
Year End
Reserves (Bcfe)
 
Gas, Oil and NGL Production (Bcfe)
 
Reserve Life
Index (1) (Years)
2012
 
3,936.1
 
319.2
 
12.3
2013
 
4,061.9
 
309.0
 
13.1
2014
 
3,931.9
 
322.7
 
12.2
 ____________________________
(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) to calculate economic producibility of reserves and the discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to Proved Reserves. Refer to Note 16 - Supplemental Oil and Gas Information (Unaudited), in Item 8 of Part II of this Annual Report on Form 10-K for additional information regarding estimates of proved reserves and the preparation of such estimates.
 

28



QEP Energy's proved reserves in major operating areas are summarized in the table below:
 
 
December 31,
 
 
2014
 
2013
Northern Region
 
(Bcfe)
 
(% of total)
 
(Bcfe)
 
(% of total)
Pinedale
 
1,450.1

 
37
%
 
1,563.2

 
39
%
Williston Basin
 
858.9

 
22
%
 
797.5

 
20
%
Uinta Basin
 
623.0

 
16
%
 
586.4

 
14
%
Other Northern
 
94.0

 
2
%
 
92.6

 
2
%
Southern Region
 
 
 


 
 
 
 
Haynesville/Cotton Valley
 
493.9

 
13
%
 
502.8

 
12
%
Permian Basin
 
375.7

 
10
%
 

 
%
Midcontinent
 
36.3

 
%
 
519.4

 
13
%
Total QEP Energy
 
3,931.9

 
100
%
 
4,061.9

 
100
%
 
Estimates of the quantity of proved reserves decreased during 2014 primarily due to sales of reserves in place related to the 2014 Midcontinent property sales and decreases in estimated proved reserves in Pinedale due to production decline on older wells and fewer proved undeveloped (PUD) reserves locations. These proved reserve decreases were partially offset by reserve additions associated with the Permian Basin Acquisition that occurred during the first quarter of 2014 and increases in estimated Williston Basin proved reserves, primarily the result of extensions and additions from the recognition of additional PUD locations due to the increased drilling program.

Proved Undeveloped Reserves
Significant changes to PUD that occurred during 2014 are summarized in the table below:
 
2014
 
(Bcfe)
Proved undeveloped reserves at January 1,
1,907.9

Transferred to proved developed reserves
(368.5
)
Revisions to previous estimates
(55.1
)
Extensions and discoveries(1)
208.2

Purchase of reserves in place(2)
216.5

Sale of reserves in place(3)
(174.6
)
Proved undeveloped reserves at December 31,(4)
1,734.4

 ____________________________
(1) 
The increase in extensions and discoveries in 2014 was the result of 123.5 Bcfe in Pinedale and 84.7 Bcfe in the Williston Basin. All of these extensions and discoveries related to new well completions and the associated new PUD locations as part of the Company's development drilling plans and new compression projections in Pinedale.
(2) 
Purchase of reserves in place in 2014 related to the Company's Permian Basin Acquisition as discussed in Note 2 - Acquisitions and Divestitures.
(3) 
Sale of reserves in place related primarily to property sales in the Midcontinent in the second and fourth quarters of 2014 as discussed in Note 2 - Acquisitions and Divestitures.
(4) 
All of QEP Energy's PUD reserves at December 31, 2014, are scheduled to be developed within five years from the date such locations were initially disclosed as PUD reserves; however, long-term development of gas reserves in Pinedale is governed by the BLM's September 2008 ROD on the FSEIS. Under the ROD, QEP Energy is allowed to drill and complete wells year-round in designated concentrated development areas. The ROD contains additional requirements and restrictions on the sequence of development, which requires the Company to develop its leasehold from the south to the north. These restrictions result in protracted, phased development that is beyond the control of the Company. The Company has an ongoing development plan and the financial capability to continue development in the manner estimated. Additionally, QEP Energy plans to develop its PUD reserves prior to lease expiration or extend the term of the lease.

The costs incurred to continue the development of PUD reserves were approximately $796.7 million, $645.9 million, and $513.0 million for the years ended December 31, 2014, 2013 and 2012, respectively. The costs incurred in 2014 related to the drilling of PUD locations in QEP's development projects. This investment resulted in the transfer of 368.5 Bcfe of PUD

29



reserves to proved developed reserves in 2014, representing 19% of the Company's total PUD reserves as of December 31, 2013.
 
Estimated future development costs relating to the development of PUD reserves are projected to be approximately $925.7 million in 2015, $983.7 million in 2016, and $714.3 million in 2017. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. PUD reserves related to major development projects will be reclassified to proved developed reserves when production commences.

Internal Controls Over Proved Reserve Estimates, Technical Qualifications and Technologies Used
Estimates of proved oil and gas 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. The Company retained Ryder Scott Company (RSC) and DeGolyer and MacNaughton (D&M), independent oil and gas reserve evaluation engineering consultants, to prepare the estimates of 100% of its proved reserves as of December 31, 2014, of which RSC prepared approximately 91% and D&M prepared approximately 9% of the Company's total net proved reserves. The Company utilized RSC to prepare the estimates of 100% of the Company's total net proved reserves as of December 31, 2013 and 2012. The individual at RSC who was responsible for overseeing the preparation of QEP's reserve estimates as of December 31, 2014, for its Haynesville, Pinedale, Williston, Other Northern, Uinta and Midcontinent areas, 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 30 years of experience in the petroleum industry, including experience estimating and evaluating petroleum reserves. The individual at D&M who was responsible for overseeing the preparation of QEP’s Permian Division reserves estimates as of December 31, 2014, is a registered Professional Engineer in the State of Texas and graduated with a Bachelor of Science degree in Petroleum Engineering from the University of Texas at Austin in 1984. The individual has over 30 years of experience in the petroleum industry, including experience estimating and evaluating petroleum reserves. A more detailed letter including each individual's professional qualifications has been filed as part of Exhibit 99.1 to this report for RSC and as part of Exhibit 99.2 for D&M.

The individual at QEP responsible for insuring the accuracy of the reserve estimate preparation material provided to RSC and D&M and reviewing the estimates of reserves received from RSC and D&M is QEP's Chief Engineer. This individual is a member of the Society of Petroleum Engineers and graduated with a Bachelors of Science degree in Petroleum Engineering from North Dakota State University in 1994. This individual has over 20 years of experience in the petroleum industry, including more than 15 years reservoir engineering experience in most of the active domestic basins in the U.S.

To establish proved 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 QEP's 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 2014, in those cases where such data were considered to be definitive. For wells currently in 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 95% 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 5% of such reserves was estimated by the volumetric method. The volumetric analysis utilizes pertinent well data furnished to RSC and D&M by QEP or obtained from available public data sources through December 2014. 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 in 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

30



limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, 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 16 - Supplemental Oil and Gas 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 reserve estimates as of December 31, 2014, with the Energy Information Administration of the Department of Energy (EIA) on Form EIA-23. Although QEP uses the same technical and economic assumptions when it prepares the Form EIA-23 as used to estimate reserves for this Annual Report on Form 10-K, it is obligated to report to the EIA reserves for only wells it operates, not for all of the wells in which it has an interest, and to include the reserves attributable to other owners in such wells.
 
Production, Prices and Production Costs
The following table sets forth the net production volumes and field-level prices of gas, oil and NGL produced, and the related operating expenses, for the years ended December 31, 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
QEP Energy
 
 
Volumes produced and sold
 
 
 

 

Gas (Bcf)
 
179.3

 
218.9

 
249.3

Oil (Mbbl)
 
17,146.5

 
10,209.7

 
6,306.9

NGL (Mbbl)
 
6,769.1

 
4,811.3

 
5,349.0

Total equivalent production (Bcfe)
 
322.7

 
309.0

 
319.2

Average field-level price (1)
 
 

 


 


Gas (per Mcf)
 
$
4.33

 
$
3.56

 
$
2.68

Oil (per bbl)
 
79.79

 
89.78

 
84.45

NGL (per bbl)
 
32.95

 
39.95

 
34.43

Lifting costs (per Mcfe)
 
 

 


 


Lease operating expense
 
$
0.74

 
$
0.59

 
$
0.55

Production taxes
 
0.63

 
0.51

 
0.30

Total lifting costs
 
$
1.37

 
$
1.10

 
$
0.85

 ____________________________
(1) 
The average field-level price does not include the impact of settled commodity price derivatives.

A summary of gas production by major geographical area is shown in the following table:
 
 
Year Ended December 31,
 
Change
 
 
2014
 
2013
 
2012

2014 vs 2013
 
2013 vs 2012
QEP Energy - Gas (Bcf)
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
Pinedale
 
75.0

 
80.0

 
77.4

 
(5.0
)
 
2.6

Williston Basin
 
6.6

 
2.7

 
0.9

 
3.9

 
1.8

Uinta Basin
 
17.9

 
18.6

 
16.3

 
(0.7
)
 
2.3

Other Northern
 
9.3

 
10.3

 
11.4

 
(1.0
)
 
(1.1
)
Southern Region
 
 
 
 
 
 

 
 
 
 
Haynesville/Cotton Valley
 
49.5

 
71.8

 
112.0

 
(22.3
)
 
(40.2
)
Permian Basin
 
3.2

 

 

 
3.2

 

Midcontinent
 
17.8

 
35.5

 
31.3

 
(17.7
)
 
4.2

Total production
 
179.3

 
218.9

 
249.3

 
(39.6
)
 
(30.4
)
 

31



A summary of oil production by major geographical area is shown in the following table:
 
 
Year ended December 31,
 
Change
 
 
2014
 
2013
 
2012
 
2014 vs 2013
 
2013 vs 2012
QEP Energy - Oil (Mbbl)
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
Pinedale
 
632.0

 
657.6

 
664.4

 
(25.6
)
 
(6.8
)
Williston Basin
 
13,130.9

 
7,026.2

 
3,029.5

 
6,104.7

 
3,996.7

Uinta Basin
 
893.3

 
924.9

 
890.9

 
(31.6
)
 
34.0

Other Northern
 
200.9

 
237.7

 
297.6

 
(36.8
)
 
(59.9
)
Southern Region
 


 


 
 

 
 
 
 
Haynesville/Cotton Valley
 
35.3

 
43.2

 
43.4

 
(7.9
)
 
(0.2
)
Permian Basin
 
1,582.2

 

 

 
1,582.2

 

Midcontinent
 
671.9

 
1,320.1

 
1,381.1

 
(648.2
)
 
(61.0
)
Total production
 
17,146.5

 
10,209.7

 
6,306.9

 
6,936.8

 
3,902.8


A summary of NGL production by major geographical area is shown in the following table:
 
 
Year ended December 31,
 
Change
 
 
2014
 
2013
 
2012
 
2014 vs 2013
 
2013 vs 2012
QEP Energy - NGL (Mbbl)
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
Pinedale
 
3,350.2

 
1,787.5

 
3,054.3

 
1,562.7

 
(1,266.8
)
Williston Basin
 
1,010.5

 
390.0

 
197.1

 
620.5

 
192.9

Uinta Basin
 
679.0

 
463.8

 
371.1

 
215.2

 
92.7

Other Northern
 
14.9

 
36.7

 
100.1

 
(21.8
)
 
(63.4
)
Southern Region
 


 


 
 

 
 
 
 
Haynesville/Cotton Valley
 
37.3

 
21.3

 
8.5

 
16.0

 
12.8

Permian Basin
 
511.0

 

 

 
511.0

 

Midcontinent
 
1,166.2

 
2,112.0

 
1,617.9

 
(945.8
)
 
494.1

Total production
 
6,769.1

 
4,811.3

 
5,349.0

 
1,957.8

 
(537.7
)
 
A summary of natural gas equivalent total production by major geographical area is shown in the following table:
 
 
Year ended December 31,
 
Change
 
 
2014
 
2013
 
2012
 
2014 vs 2013
 
2013 vs 2012
QEP Energy - Total Production (Bcfe)
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
Pinedale
 
98.9

 
94.7

 
99.7

 
4.2

 
(5.0
)
Williston Basin
 
91.4

 
47.2

 
20.3

 
44.2

 
26.9

Uinta Basin
 
27.3

 
26.9

 
23.9

 
0.4

 
3.0

Other Northern
 
10.6

 
11.9

 
13.7

 
(1.3
)
 
(1.8
)
 
 
 

 
 

 
 
 
 
 
 
Southern Region
 
 
 
 
 
 
 
 
 
 
Haynesville/Cotton Valley
 
49.9

 
72.2

 
112.3

 
(22.3
)
 
(40.1
)
Permian Basin
 
15.8

 

 

 
15.8

 

Midcontinent
 
28.8

 
56.1

 
49.3

 
(27.3
)
 
6.8

Total production
 
322.7

 
309.0

 
319.2

 
13.7

 
(10.2
)
 

32



A regional comparison of average field-level prices is shown in the following table:
 
Year Ended December 31,
 
Change
 
2014
 
2013
 
2012
 
2014 vs 2013
 
2013 vs 2012
QEP Energy - Average field-level gas price (per Mcf)
 
 
 
 
Northern Region
$
4.26

 
$
3.58

 
$
2.64

 
$
0.68

 
$
0.94

Southern Region
4.44

 
3.54

 
2.70

 
0.90

 
0.84

Average field-level gas price
4.33

 
3.56

 
2.68

 
0.77

 
0.88

QEP Energy - Average field-level oil price (per bbl)
 
 

 
 

Northern Region
$
78.87

 
$
89.35

 
$
83.03

 
$
(10.48
)
 
$
6.32

Southern Region
85.76

 
92.60

 
89.32

 
(6.84
)
 
3.28

Average field-level oil price
79.79

 
89.78

 
84.45

 
(9.99
)
 
5.33

QEP Energy - Average field-level NGL price (per bbl)
 
 

 
 

Northern Region
$
33.22

 
$
46.56

 
$
36.17

 
$
(13.34
)
 
$
10.39

Southern Region
32.15

 
31.65

 
30.44

 
0.50

 
1.21

Average field-level NGL price
32.95

 
39.95

 
34.43

 
(7.00
)
 
5.52


Northern Region

Pinedale
Production from Pinedale increased 4% to 98.9 Bcfe during 2014 compared to 2013. This increase in production was primarily a result of increased NGL production due to recovering ethane throughout the majority of 2014 compared to rejecting ethane throughout the majority of 2013.

Production from Pinedale decreased 5% to 94.7 Bcfe during 2013 compared to 2012. This decrease in production was primarily a result of lower NGL production due to rejecting ethane throughout the majority of 2013 compared to recovering ethane throughout the majority of 2012. Additionally, QEP had a lower average interest in wells drilled in the 2013 drilling program.

During each of the three years ended December 31, 2014, 2013 and 2012, Pinedale's production represented 31% of QEP Energy's total production.

Williston Basin
In the Williston Basin, production increased 94% to 91.4 Bcfe during 2014 compared to 2013, primarily due to increased oil and NGL production. The increase in production volumes was primarily attributable to ongoing development of the properties acquired in the Williston Basin Acquisition, which contributed 6,347.5 Mbbls of increased oil and NGL volume. The remaining 377.7 Mbbls increase in 2014 related to increased development drilling on QEP's existing pre-acquisition acreage.

During 2013, production increased 133% to 47.2 Bcfe compared to 2012, due to increased oil and NGL production. The increase in production volumes was primarily attributable to ongoing development of the properties acquired in the Williston Basin Acquisition, which contributed 2,591.6 Mbbls of increased oil and NGL volume. The remaining 1,598.0 Mbbls increase in 2013 is related to increased development drilling on QEP's existing pre-acquisition acreage.

During the years ended December 31, 2014, 2013 and 2012, Williston Basin production represented 28%, 15%, and 6% of QEP Energy's total production, respectively.

Uinta Basin
In the Uinta Basin, production increased 1% to 27.3 Bcfe during 2014, compared to 2013, due primarily to increased NGL production as a result of recovering ethane throughout the majority of 2014 compared to rejecting ethane in the majority of 2013.

During 2013, production increased 13% to 26.9 Bcfe due to increased drilling activity in the Lower Mesaverde formation in the Red Wash Unit. NGL production increased 92.7 Mbbls during 2013 compared to 2012, primarily as a result of QEP Energy executing a fee-based cryogenic processing agreement with QEP Field Services for a portion of the Red Wash Unit's gas production in mid-2012, which was partially offset by decreased overall NGL production due to ethane rejection throughout the majority of 2013.

33




During the years ended December 31, 2014, 2013 and 2012, Uinta Basin production represented 8%, 9%, and 7%, respectively, of QEP Energy's total production.

Other Northern
QEP Energy's Other Northern production decreased 11% to 10.6 Bcfe during 2014 compared to 2013, due to declining production from older wells and lack of new drilling.

Other Northern production decreased 13% to 11.9 Bcfe during the year ended December 31, 2013 compared to 2012, due to declining production from older wells and the divestiture of certain of QEP's noncore properties in the Northern Region during 2013.

During the year ended December 31, 2014, Other Northern production represented 3% of QEP Energy's total production, compared to 4% for each of the years ended December 31, 2013 and 2012.

Southern Region

Haynesville/Cotton Valley
Production from the Haynesville Shale and Cotton Valley decreased 31% to 49.9 Bcfe during 2014 when compared to 2013. Decreased production was due to declining production as QEP's drilling program remained suspended in the area due to depressed gas prices and QEP's focus on developing more liquids rich areas during 2014.

Production from the Haynesville Shale and Cotton Valley decreased 36% to 72.2 Bcfe during 2013 when compared to 2012. Decreased production was due to the suspension of QEP's drilling program in the area due to depressed gas prices and QEP's focus on developing more liquids rich areas during 2013.

During the years ended December 31, 2014, 2013 and 2012, Haynesville/Cotton Valley's production comprised 15%, 23%, and 35% of QEP Energy's total production, respectively.

Permian Basin
In February 2014, QEP Energy acquired approximately 26,500 net acres of producing and undeveloped oil and gas properties in the Permian Basin. Production from the Permian Basin was 15.8 Bcfe during the period from February 25, 2014, through December 31, 2014, which comprised 5% of QEP Energy's total production.

Midcontinent
Production in the Midcontinent decreased 49% to 28.8 Bcfe during 2014 when compared to 2013, due primarily to the sale of QEP's interest in properties in the Midcontinent area at the end of the second quarter of 2014.

Production in the Midcontinent grew 14% to 56.1 Bcfe during 2013 compared to 2012, driven by a 494.1 Mbbl increase in NGL production and a 4.2 Bcfe increase in gas production offset by decreased oil production of 61.0 Mbbl. The increase in gas and NGL production was driven by several high rate and high working interest well completions in 2013.

During the years ended December 31, 2014, 2013 and 2012, Midcontinent's production represented 9%, 18%, and 15% of QEP Energy's total production, respectively.

34




Productive Wells
The following table summarizes the Company's productive wells as of December 31, 2014, all of which are located in the U.S.:
 
 
Gas
 
Oil
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
Pinedale
 
903

 
594

 

 

 
903

 
594

Williston Basin
 

 

 
554

 
226

 
554

 
226

Uinta Basin
 
694

 
426

 
1,542

 
209

 
2,236

 
635

Other Northern
 
539

 
182

 
29

 
9

 
568

 
191

Southern Region
 
 
 
 
 
 
 
 
 
 
 
 
Haynesville/Cotton Valley
 
815

 
453

 
1

 

 
816

 
453

Permian Basin
 




338


315


338


315

Midcontinent
 
799

 
245

 
46

 
15

 
845

 
260

Total productive wells (1)
 
3,750

 
1,900

 
2,510

 
774

 
6,260

 
2,674

____________________________
(1) 
As of December 31, 2014, QEP owned interests in 90 gross wells containing multiple completions.

The term "gross" refers to all wells or acreage in which QEP has a partial working interest and the term "net" refers to QEP's ownership represented by that working interest. Although many wells produce both oil and gas, and many gas wells also have allocated NGL volumes from processing, a well is categorized as either a 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.

The Company also holds numerous overriding royalty interests in oil and gas wells, a portion of which is convertible to working interests after recovery of certain costs by third parties. Once the overriding royalty interests are converted to working interests, these wells are included in the Company's gross and net well count.
 
Leasehold Acreage
The following table summarizes developed and undeveloped leasehold acreage in which the Company owns a working interest or mineral interest as of December 31, 2014. "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.

35



 
 
Developed Acres (1)
 
Undeveloped Acres (2)
 
Total Acres
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
Colorado
 
173,015

 
117,181

 
80,737

 
19,030

 
253,752

 
136,211

Montana
 
37,897

 
15,649

 
331,566

 
58,038

 
369,463

 
73,687

New Mexico
 
7,740

 
4,266

 
24,651

 
2,476

 
32,391

 
6,742

North Dakota
 
180,779

 
42,652

 
193,303

 
78,206

 
374,082

 
120,858

South Dakota
 
40

 
40

 
203,330

 
107,551

 
203,370

 
107,591

Wyoming
 
314,516

 
210,266

 
180,942

 
123,327

 
495,458

 
333,593

Utah
 
230,726

 
177,654

 
174,708

 
105,016

 
405,434

 
282,670

Other
 
14,215

 
3,885

 
156,065

 
42,217

 
170,280

 
46,102

Southern Region
 
 
 
 
 
 
 
 
 


 


Arkansas
 
17,942

 
10,095

 
823

 
2,470

 
18,765

 
12,565

Kansas
 
46,273

 
20,872

 
35,579

 
15,394

 
81,852

 
36,266

Louisiana
 
69,868

 
62,044

 
1,444

 
1,495

 
71,312

 
63,539

Oklahoma
 
139,501

 
74,947

 
143,515

 
50,936

 
283,016

 
125,883

Texas
 
31,179

 
22,495

 
12,804

 
10,445

 
43,983

 
32,940

Other
 

 

 
1,757

 
1,300

 
1,757

 
1,300

Total
 
1,263,691

 
762,046

 
1,541,224

 
617,901

 
2,804,915

 
1,379,947

 ____________________________
(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 oil and gas 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,
 
 
 
 
2015
 
92,572

 
73,700

2016
 
29,905

 
28,439

2017
 
58,373

 
54,832

2018
 
8,468

 
8,124

2019 and later
 
39,801

 
37,016

Total
 
229,119

 
202,111



36



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, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Northern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pinedale
 
116

 
82.4

 

 

 

 

 

 

Williston Basin
 
199

 
80.6

 

 

 

 

 

 

Uinta Basin
 
196

 
6.5

 

 

 

 

 

 

Other Northern
 
3

 
3.0

 

 

 
1

 
1.0

 

 

Southern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haynesville/Cotton Valley
 
40

 
3.2

 
1

 
0.3

 

 

 

 

Permian Basin
 
71

 
63.2

 

 

 

 

 

 

Midcontinent
 
32

 
2.3

 

 

 

 

 

 

Total
 
657

 
241.2

 
1

 
0.3

 
1

 
1.0

 

 

Year Ended December 31, 2013
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Northern Region
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Pinedale
 
111

 
61.5

 

 

 

 

 

 

Williston Basin
 
176

 
70.7

 

 

 

 

 

 

Uinta Basin
 
224

 
39.4

 

 

 

 

 

 

Other Northern
 
6

 
0.2

 

 

 

 

 
1

 
1.0

Southern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haynesville/Cotton Valley
 
11

 
3.4

 

 

 

 

 

 

Midcontinent
 
135

 
29.3

 

 

 

 

 

 

Total
 
663

 
204.5

 

 

 

 

 
1

 
1.0

Year Ended December 31, 2012
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Northern Region
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Pinedale
 
102

 
73.3

 

 

 

 

 

 

Williston Basin
 
88

 
28.0

 

 

 

 

 

 

Uinta Basin
 
254

 
45.1

 

 

 
1

 
0.6

 

 

Other Northern
 
31

 
6.6

 

 

 

 

 

 

Southern Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Haynesville/Cotton Valley
 
35

 
15.7

 

 

 
2

 
1.6

 

 

Midcontinent
 
157

 
32.2

 

 

 

 

 

 

Total
 
667

 
200.9

 

 

 
3

 
2.2

 

 




37



The following table presents operated and non-operated well completions for the year ended December 31, 2014:
 
Operated Completions
 
Non-operated Completions
 
Gross
 
Net
 
Gross
 
Net
Northern Region
 
 
 
 
 
 
 
Pinedale
116

 
82.4

 

 

Williston Basin
88

 
72.9

 
111

 
7.7

Uinta Basin
7

 
6.0

 
189

 
0.5