10-K

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, 2017

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, a smaller reporting company, or an emerging growth company. See definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth" 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
			Emerging growth company	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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, 2017): $2,429,606,369.

At January 31, 2018, there were 240,968,931 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 2018 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
Where You Can Find More Information		2
Forward-Looking Statements		2
Glossary of Terms		6
	PART I
ITEMS 1 & 2.	BUSINESS AND PROPERTIES	9
ITEM 1A.	RISK FACTORS	31
ITEM 1B.	UNRESOLVED STAFF COMMENTS	47
ITEM 3.	LEGAL PROCEEDINGS	48
ITEM 4.	MINE SAFETY DISCLOSURES	48
	PART II
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	49
ITEM 6.	SELECTED FINANCIAL DATA	52
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	55
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	75
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	77
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	123
ITEM 9A.	CONTROLS AND PROCEDURES	123
ITEM 9B.	OTHER INFORMATION	124
	PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	127
ITEM 11.	EXECUTIVE COMPENSATION	127
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	127
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	127
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	127
	PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENTS SCHEDULES	127
ITEM 16.	FORM 10-K SUMMARY	132

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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 800-732-0330 for further information on the operation of the Public Reference Room. The SEC also maintains an Internet site at 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 this 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 Code of Conduct.

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 17^th Street, Suite 800, Denver, CO 80265 (telephone number: 303-672-6900).

Cautionary Statement Regarding 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:

• focus on returns-focused growth and superior execution and strategies to achieve these objectives;

• our strategic objectives to transition to a pure-play Permian Basin company;

• plans to grow oil and gas production;

• impact on production from disruptions in transportation and midstream services;

• drilling and completion plans and strategies;

• refracturing of wells in the Haynesville/Cotton Valley and the Williston Basin;

• adding additional acreage in the Permian Basin;

• estimated reserves and development of such reserves;

• managing counterparty risk exposure;

• expectations and assumptions regarding oil, gas and NGL prices;

• development of proved undeveloped (PUD) reserves within five years;

• reclassification of PUD reserves;

• PUD conversion rates and factors impacting conversion of PUD reserves;

• future development costs and funding for same;

• factors affecting our decision to modify our development plans;

• impact of weather on drilling, completion and production operations;

• our ability to meet delivery and sales commitments;

• impact of and compliance with government regulations;

• FERC regulation of oil and gas pipelines;

• impact of tax reform legislation on our tax position;

• adequacy of insurance;

• volatility of oil, gas and NGL prices and factors impacting such prices;

• delays caused by transportation, processing, storage and refining capacity issues;

• impact of shutting in wells;

• factors impacting our ability to transport oil and gas;

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• credit agreement limitations that could prevent QEP from incurring certain indebtedness, which could limit QEP's ability to engage in acquisitions;

• credit agreement limitations on divestitures;

• impact of potential activist shareholders to our operations, personnel retention, strategies and costs;

• the conditions impacting the timing and amount of share repurchases under our share repurchase program;

• incurring penalties and capital expenditures to address air emission noncompliance issues;

• the underfunded status of our pension plan;

• impact of our charter and bylaws on a potential takeover;

• the usefulness of Adjusted EBITDA (a non-GAAP financial measure) and adjustments made to net income to arrive at Adjusted EBITDA;

• our inventory of drilling locations;

• aggregate purchase price for acquisitions of additional oil and gas interests in the Permian Basin pursuant to offers made in the fourth quarter of 2017;

• evaluation of potential acquisitions, divestitures and joint venture opportunities;

• plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley to simplify our asset portfolio;

• growing oil and NGL production and transitioning to a more balanced portfolio;

• our balance sheet and sufficient liquidity providing for the ability to grow oil production;

• adjustments to our capital investment program based on a variety of factors, including an evaluation of drilling and completion activities and drilling results;

• focus on operating costs and per well drilling costs;

• amount and allocation of forecasted capital expenditures (excluding property acquisitions) and, plans for funding operations and capital investments;

• impact of lower or higher commodity prices and interest rates;

• focus on a sufficient liquidity position to ensure financial flexibility;

• potential for asset impairments and factors impacting impairment amounts;

• plans to recover or reject ethane from produced natural gas;

• fair value estimates and related assumptions and assessment of the sensitivity of changes in assumptions, and critical accounting estimates, including estimated asset retirement obligations;

• impact of global geopolitical and macroeconomic events and the monitoring of such events;

• plans regarding derivative contracts, including the volumes utilized, and the anticipated benefits derived there from;

• outcome and impact of various claims;

• estimated amount of potential impairment of proved and unproved property, primarily in the Williston Basin;

• expected cost savings and other efficiencies from multi-well pad drilling, including "tank-style" development;

• delays in completion of wells, well shut-ins and volatility to operating results caused by multi-well pad drilling;

• predictability and success of our drilling operations;

• plans and ability to pursue acquisition opportunities;

• value of pension plan assets and our plans regarding additional contributions to our pension plan;

• oil exports from and imports to the U.S.;

• mitigation of losses related to unutilized capacity under transportation commitments and storage activities;

• inflation and deflation;

• sufficiency of our liquidity position to ensure financial flexibility and fund our operations and capital expenditures;

• estimates of the amount of additional indebtedness we may incur under our revolving credit facility;

• factors adversely impacting our liquidity;

• off-balance sheet arrangements;

• impact of inflation and price changes on our ability to raise capital, borrow money and retain personnel;

• leasehold development and financial capability to continue planned development;

• estimates of environmental remediation costs and factors impacting such estimates;

• changes in recorded goodwill and bargain purchase gains;

• adequacy of tax accruals and potential changes to such accruals;

• redemption of senior notes

• factors impacting our ability to borrow and the interest rates offered;

• loss contingencies;

• factors impacting bad debt expense;

• unrecognized tax benefits and the realization of those benefits;

• implementation and impact of new accounting pronouncements;

• pro forma results for acquired properties;

• estimates of future liability for deficiency charges in connection with the divestiture of our assets in Pinedale (the Pinedale Divestiture);

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• assumptions regarding share-based compensation;

• settlement of performance share units and restricted share units in cash;

• employee benefit plan gains or losses;

• recognition of compensation costs related to share-based compensation grants;

• impact of tax regulatory guidance on financial statements;

• realization of alternative minimum tax credits; and

• estimated general and administrative expenses related to our retention and severance program.

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 in Part I, Item 1A of this Annual Report on Form 10-K;

• changes in oil, gas and NGL prices;

• global geopolitical and macroeconomic factors;

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

• the risks and liabilities associated with acquired assets;

• asset impairments;

• liquidity constraints, including those resulting from the cost and availability of debt and equity financing;

• drilling and completion strategies, methods and results;

• assumptions around well density/spacing and recoverable reserves per well prove to be inaccurate;

• changes in estimated reserve quantities;

• changes in management's assessments as to where QEP's capital can be most profitably deployed;

• shortages and costs of oilfield equipment, services and personnel;

• changes in development plans;

• lack of available pipeline, processing and refining capacity;

• processing volumes and pipeline throughput;

• risks associated with hydraulic fracturing;

• the outcome of contingencies such as legal proceedings;

• delays in obtaining permits and governmental approvals;

• operating risks such as unexpected drilling conditions and risks inherent in the production of oil and gas;

• weather conditions;

• changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning: the environment, climate change, greenhouse gas or other emissions, natural resources, fish and wildlife, hydraulic fracturing, water use and drilling and completion techniques, as well as the risk of legal proceedings arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;

• derivative activities;

• potential losses or earnings reductions from our commodity price risk management programs;

• volatility in the commodity-futures market;

• failure of internal controls and procedures;

• failure of our information technology infrastructure or applications to prevent a cyberattack;

• elimination of federal income tax deductions for oil and gas exploration and development costs;

• production, severance and property taxation rates;

• discount rates;

• regulatory approvals and compliance with contractual obligations;

• actions of, or inaction by federal, state, local or tribal governments, foreign countries and the Organization of Petroleum Exporting Countries;

• lack of, or disruptions in, adequate and reliable transportation for our production;

• competitive conditions;

• production and sales volumes;

• actions of operators on properties in which we own an interest but do not operate;

• estimates of oil and gas reserve quantities;

• reservoir performance;

• operating costs;

• inflation;

• capital costs;

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• creditworthiness and performance of the Company's counterparties, including financial institutions, operating partners and other parties;

• volatility in the securities, capital and credit markets;

• actions by credit rating agencies and their impact on the Company;

• changes in guidance issued related to tax reform legislation;

• actions of activist shareholders; 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, loss from early extinguishment of debt and certain other items.

Argus WTI Midland An index price reflecting the weighted average price of WTI at the pipeline and storage hub at Midland, Texas.

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 swap A financial derivative that fixes the price difference between two sales points for a specified commodity volume over a specified time period.

Boe Barrels of oil equivalent.

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.

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.

dry hole An exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

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.

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 forthe Northwest Pipeline Corporation Rocky Mountains.

M Thousand.

MM Million.

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mineral interest The economic interest or ownership of minerals, giving the owner the right to a share of the minerals produced or proceeds from the sale of the minerals.

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 six Mcf 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 the sum of the fractional working interest the Company owns in the gross wells or acres. "Net" revenues are QEP Resources Inc.'s share of revenues from wells after deductions of royalties, overrides, net profits and other lease burdens.

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.

oil equivalents Natural gas is converted to a crude oil equivalent at the ratio of six Mcf of natural gas to one barrel of crude oil equivalent.

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

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.

proved developed reserves Reserves that are 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.

proved properties Properties with proved reserves.

proved reserves Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

proved undeveloped reserves or PUD reserves Proved undeveloped reserves or PUD reserves are those reserves 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. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

PUD reserves conversion rate The percentage of PUDs transferred to proved developed over total PUD reserves as of the prior year end.

reserves Estimated remaining quantities of crude oil, natural gas 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.

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reservoir An 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.

resource play Refers to regionally distributed oil and natural gas accumulation as opposed to conventional plays which are more limited in 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 mineral 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, completing or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the minerals at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

seismic data 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.

undeveloped reserves Reserves of any category that are expected to be recovered from new wells or from existing wells where a relatively major expenditure is required for recompletion.

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 2017

PART I

ITEMS 1 and 2. BUSINESS AND PROPERTIES

Nature of Business

QEP Resources, Inc. (QEP or the Company) is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Northern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".

Change in Segment Reporting due to Discontinued Operations and Termination of Marketing Agreements

In December 2014, the Company sold substantially all of its midstream business, including the Company's ownership interest in QEP Midstream Partners, LP (QEP Midstream), to Tesoro Logistics LP for total cash proceeds of approximately $2.5 billion, including $230.0 million to refinance debt at QEP Midstream, and QEP recorded a pre-tax gain of approximately $1.8 billion for the year ended December 31, 2014 (Midstream Sale). As a result of the Midstream Sale, the results of operations for the QEP Field Services Company (QEP Field Services), excluding the retained ownership of Haynesville Gathering, were classified as discontinued operations in the Consolidated Financial Statements.

Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and Haynesville Gathering. As a result, QEP Energy directly markets its own oil, gas and NGL production. While QEP continues to act as an agent for the sale of oil, gas and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had prior to 2016.

In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP had one reportable segment effective January 1, 2016. The Company has recast its financial statements for historical periods to reflect the impact of the termination of marketing agreements to show its financial results without segments.

Financial and Operating Highlights

During the year ended December 31, 2017, QEP:

• Generated net income of $269.3 million, or $1.12 per diluted share;

• Reported $736.1 million of Adjusted EBITDA (a non-GAAP measure defined and reconciled in Item 7 of Part II of this Annual Report on Form 10-K), a 17%increase over 2016;

• Recognized realized oil prices that were $6.07 per bbl, or 14% higher compared to 2016;

• Divested assets in Pinedale for approximately $718.2 million;

• Delivered oil equivalent production of 53.1 MMboe, a 5%decrease from 2016;

• Delivered record oil production of 6.1 MMbbls in the Permian Basin, a 52%increase over 2016;

• Reported year end total proved reserves of 684.7 MMboe, including record proved crude oil reserves of 320.5 MMbbl;

• Incurred capital expenditures (excluding property acquisitions) of $1,219.8 million, a 130% increase over 2016;

• Acquired various oil and gas properties for approximately $815.2 million, of which the vast majority were properties in the Permian Basin;

• Expanded our successful refracturing program in Haynesville/Cotton Valley and began refracturing wells in the Williston Basin; and

• Issued $500.0 million of senior notes and repaid $445.7 million of senior notes, which were due in 2018, 2020 and 2021; paid fees and expenses associated with the repayment and used the remainder for general corporate purposes.

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Strategies

We are focused on creating value for our shareholders through returns-focused growth and superior execution. To achieve these objectives we strive to:

• operate in a safe and environmentally responsible manner;

• simplify our asset portfolio and focus on our Permian Basin assets;

• maintain an inventory of high return development projects in the Permian Basin;

• allocate capital to those projects that generate the highest returns;

• increase oil production as a percentage of total production;

• acquire businesses and assets that complement or expand our current business;

• build contiguous acreage positions that drive operating efficiencies;

• be the operator of our assets, whenever possible;

• be the low-cost driller and producer where we operate;

• actively market our production to maximize value;

• utilize derivative contracts to reduce the impact of oil, gas and NGL price volatility;

• attract and retain the best people; and

• maintain a capital structure that provides sufficient financial flexibility to successfully operate and grow the business.

Overview

QEP conducts exploration and production (E&P) activities in several of North America's most important hydrocarbon resource plays. QEP has an inventory of developed and identified undeveloped drilling locations in the Permian Basin in western Texas, the Williston Basin in North Dakota, Haynesville/Cotton Valley in northwestern Louisiana, the Uinta Basin in eastern Utah and other proven properties in Wyoming, Utah and Colorado.

While historically the Company has been more natural gas-weighted, in recent years the Company has increased its focus on growing its oil and NGL production. Since the beginning of 2012, the Company has made approximately $3.9 billion of acquisitions of oil-weighted properties, spent approximately 60% of its capital expenditures (excluding property acquisitions) on its oil-weighted properties, and divested gas-weighted properties, such as Pinedale. Compared to 2011, the Company's 2017 oil production has grown 424% and the Company's 2017 oil and NGL production represented 47% of total production compared to 14% in 2011. Additionally, oil and NGL revenue represented 68% of total field-level revenues during 2017 compared to 27% in 2011. Approximately 56% of total proved reserves at year-end 2017 were oil and NGL. Consistent with its emphasis on oil-weighted properties, QEP now reflects its production and reserve amounts in oil equivalent volumes rather than gas equivalent volumes. In February 2018, QEP's Board of Directors has unanimously approved several strategic initiatives including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin.

In the fourth quarter of 2017, QEP closed on the acquisition of oil and gas properties in the Permian Basin (the 2017 Permian Basin Acquisition) for an aggregate purchase price of $720.7 million, subject to post-closing purchase price adjustments. The 2017 Permian Basin Acquisition consists of approximately 15,100 acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. In addition, QEP has made offers to various persons who own additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the purchase. If all offers are accepted, QEP now expects that the aggregate purchase price will not exceed $50.0 million. In February 2018, QEP entered into agreements related to these offers for an aggregate purchase price of $36.1 million, subject to customary purchase price adjustments. The transactions and remaining offers, if accepted, are expected to be funded with borrowings under the credit facility and are expected to close in the first half of 2018. QEP received aggregate proceeds of $806.8 million related to the sales of our Pinedale assets (the Pinedale Divestiture) and other properties during the year ended December 31, 2017. All of the proceeds from the Pinedale Divestiture were used to close the 2017 Permian Basin Acquisition.

In the fourth quarter of 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $591.0 million, (the 2016 Permian Basin Acquisition). The 2016 Permian Basin Acquisition consists of approximately 9,600 net acres in Martin County, Texas, which are primarily held by production from existing vertical wells. The 2016 Permian Basin Acquisition was funded with proceeds from an equity offering in June 2016 and cash on hand.

10

In addition, the following map illustrates the location of the Company's significant E&P activities, the location of its Northern and Southern Regions, and related reserve and production data during December 31, 2017:

QEP sells gas volumes to wholesale marketers, industrial users, local distribution companies, midstream service providers and utility companies. QEP sells oil and NGL volumes to refiners, marketers, midstream service providers and other companies, including some with pipeline facilities near QEP's producing properties. QEP regularly evaluates counterparty credit risk and may require parental guarantees, letters of credit or prepayment from companies with perceived higher credit risk. In order to get its oil, gas and NGL volumes to their ultimate sale point, QEP has contracts with midstream providers for the gathering, transportation, processing and/or fractionation of these products. In addition, QEP has firm transportation commitments with interstate pipelines to move its gas volumes to multiple destinations dependent upon market conditions. Disruptions impacting pipelines or other midstream providers' facilities can impact QEP's production volumes. In cases where QEP's wells are not connected to sales pipelines, the Company sells its products to buyers at the well and the buyer arranges transportation to the ultimate destination.

Description of Properties

Northern Region

Williston Basin

QEP has 362.0 net productive wells (including its interest in non-operated wells) in the Williston Basin that generate substantial cash flows, which help fund future development of the Company's portfolio of assets. QEP has developed a majority of its acreage but continues its drilling program targeting the Bakken and Three Forks formations. In addition, QEP initiated a refracturing program in the Williston Basin. As of December 31, 2017, QEP had one operated rig drilling in the Williston Basin.

11

Pinedale

In September 2017, QEP divested of its Pinedale assets for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to post-closing purchase price adjustments, and recorded a pre-tax gain on sale of $180.4 million, which was recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations.

Uinta Basin

The majority of the Uinta Basin's proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs. In 2017, QEP changed from a vertical well development plan to a horizontal well development plan and has a large inventory of remaining future locations. As of December 31, 2017, QEP had one operated rig drilling in the Uinta Basin.

Other Northern

The remainder of QEP's Northern Region leasehold interests and proved reserves are distributed over a number of fields and properties in various states. During 2017, QEP sold the majority of its non-core properties in this area.

Southern Region

Permian Basin

QEP has 590.2 net productive wells in the Permian Basin. QEP has multiple targeted formations within its acreage in the Permian Basin and is actively developing oil producing zones, primarily in the Spraberry Shale and Wolfcamp formations. QEP continues to actively acquire acreage in the basin and in 2017, acquired approximately 17,000 additional net acres. QEP is utilizing a "tank-style" completion methodology and continues to test additional formations and evaluate the appropriate ultimate density of its development program. As of December 31, 2017, QEP had six operated rigs drilling in the Permian Basin.

Haynesville/Cotton Valley

QEP owns producing and undeveloped properties in Haynesville/Cotton Valley and additional lease rights that cover the overlying Hosston and Cotton Valley formations. QEP has 507.0 net productive wells, including its interest in non-operated wells, in Haynesville/Cotton Valley. Production is primarily dry gas and QEP has numerous future locations to fully develop its acreage. In addition, the Company began a refracturing program in 2016 and continued throughout 2017 and into 2018 on QEP operated wells. As of December 31, 2017, QEP had one operated rig drilling in Haynesville/Cotton Valley.

Other Southern

The remainder of QEP's Southern Region primarily consists of small royalty interests over a few properties.

Reserves

At December 31, 2017 and 2016, QEP's estimated proved reserves were approximately 684.7 MMboe and 731.4 MMboe, respectively, of which 98% and 97%, respectively, were Company operated. Proved developed reserves represented 37% and 49% of the Company's total proved reserves at December 31, 2017 and 2016, respectively, while the remaining reserves were classified as proved undeveloped. All reported reserves are located in the United States. QEP's estimated proved reserves are summarized in the table below:

	December 31, 2017				December 31, 2016
	Oil	Gas(1)	NGL	Total(1)	Oil	Gas(1)	NGL	Total(1)
	(MMbbl)	(Bcf)	(MMbbl)	(MMboe)(2)	(MMbbl)	(Bcf)	(MMbbl)	(MMboe)(2)
Proved developed reserves	116.0	655.5	27.9	253.1	103.2	1,309.8	35.7	357.2
Proved undeveloped reserves	204.5	1,138.1	37.3	431.6	135.4	1,244.0	31.5	374.2
Total proved reserves	320.5	1,793.6	65.2	684.7	238.6	2,553.8	67.2	731.4

____________________________

⁽¹⁾  Generally, gas consumed in operations was excluded from reserves, however, in some cases; produced gas consumed in operations was included in reserves when the volumes replaced fuel purchases.

⁽²⁾  Natural gas is converted to a crude oil equivalent at the ratio of six Mcf of natural gas to one barrel of crude oil equivalent.

12

QEP's reserve, production and reserve life index for each of the years ended December 31, 2015, through December 31, 2017, are summarized in the table below:

Year Ended December 31,	Year End Reserves (MMboe)	Oil, Gas and NGL Production (MMboe)	Reserve Life Index(1)(2) (Years)
2015	603.4	54.5	11.1
2016	731.4	55.8	13.1
2017	684.7	53.1	12.9

____________________________

⁽¹⁾  Reserve life index is calculated by dividing year-end proved reserves by production for that year.

⁽²⁾  The reserve life index for 2017 includes 9.9 MMboe of production volumes from Pinedale but no year-end reserves as a result of the Pinedale Divestiture in September 2017. Excluding production volumes from the divested Pinedale assets, the reserve life index is 15.8 years for the year ended December 31, 2017.

Proved Reserves

Proved reserve estimates and related information is presented consistent with the requirements of the SEC's rules for the Modernization of Oil and Gas Reporting. These rules permit 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 14 – 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.

QEP's proved reserves in its major operating areas are summarized in the table below:

	December 31,
	2017			2016
Northern Region	(MMboe)	(% of total)		(MMboe)	(% of total)
Williston Basin	146.9	21	%	160.2	22	%
Pinedale	—	—	%	160.7	22	%
Uinta Basin	100.8	15	%	106.1	14	%
Other Northern	4.5	1	%	12.3	2	%
Southern Region
Permian Basin	272.7	40	%	147.8	20	%
Haynesville/Cotton Valley	159.8	23	%	144.3	20	%
Other Southern	—	—	%	—	—	%
Total proved reserves	684.7	100	%	731.4	100	%

QEP's total proved reserves as of December 31, 2017, decreased 46.7 MMboe from December 31, 2016, primarily due to the Pinedale Divestiture, which was partially offset by an increase of proved reserves as a result of extensions and discoveries in the Permian Basin and the acquisition of reserves from the 2017 Permian Basin Acquisition. Williston Basin proved reserves decreased primarily from under performance of wells in our high density pilot test areas. Other Northern proved reserves decreased primarily due to property divestitures in 2017. Uinta Basin proved reserves decreased primarily due to changing from a vertical well development plan to a horizontal well development plan. Haynesville/Cotton Valley's increase of proved reserves is primarily the result of the successful refracturing program in 2017.

13

Proved Undeveloped Reserves

Significant changes to PUD reserves that occurred during 2017 are summarized in the table below:

	2017
	(MMboe)
Proved undeveloped reserves at January 1,	374.2
Transferred to proved developed reserves	(36.5	)
Revisions to previous estimates	(26.3	)
Extensions and discoveries	71.8
Purchase of reserves in place	71.9
Sale of reserves in place	(23.5	)
Proved undeveloped reserves at December 31,	431.6

Transfers to proved developed reserves. The costs incurred for the development of PUD reserves were approximately $389.3 million, $258.1 million and $490.4 million for the years ended December 31, 2017, 2016 and 2015, respectively. Costs incurred for the development of PUD reserves increased in 2017 from 2016, however the amount of reserves converted decreased because 16.4 MMboe of PUD reserves were converted in 2016 as a result of installation of additional centralized compression in Pinedale which did not have any associated development costs.

QEP's planned and actual transfers of proved undeveloped reserves to proved developed reserves results for the year ended December 31, 2017 are summarized in the table below:

	Planned Transfers to Proved Developed Reserves in 2017 as of December 31, 2016 (PUD conversions)		Actual Transfers to Proved Developed Reserves in 2017 (PUD conversions)		Difference
	(MMboe)
Northern Region
Williston Basin	10.6		16.3		5.7
Pinedale	3.2		6.2		3.0
Uinta Basin	—		—		—
Other Northern	—		—		—
Southern Region
Permian Basin	25.1		16.7		(8.4	)
Haynesville/Cotton Valley	6.5		3.5		(3.0	)
Other Southern	—		—		—
Total	45.4		42.7		(2.7	)
Pinedale(1)	(3.2	)	(6.2	)	(3.0	)
Total excluding Pinedale	42.2		36.5		(5.7	)

____________________________

⁽¹⁾  Pinedale PUD reserve conversions in 2017 include actual activity through the closing date of the Pinedale Divestiture.

QEP transferred 36.5 MMboe of PUD reserves to proved developed reserves in 2017 compared to 45.4 MMboe that were planned for 2017. QEP's PUD reserves conversion rate (the percentage of booked PUD reserves) was 10%, 18% and 23% for the years ended December 31, 2017, 2016 and 2015, respectively. At December 31, 2016, QEP's planned PUD reserve conversion rate for 2017 was 12.1%. QEP converted fewer PUD reserves than expected primarily due to unforeseen drilling delays in the Permian Basin as we continued to refine our "tank-style" development and changes in estimated well spacing, which led to drilling more unproved locations than initially planned. In both Haynesville/Cotton Valley and Pinedale, we had property divestitures that had PUD conversions in 2017, but because these properties were no longer owned at December 31, 2017, these PUD conversions are not part of our year end 2017 conversions to proved developed reserves. In addition, the PUD reserve conversions in Haynesville/Cotton Valley were lower than planned conversions due to the delayed arrival of the drilling rig in 2017. These lower than planned PUD conversions were partially offset by a higher PUD conversion rate in the Williston Basin as we shifted more development to PUD locations from the unproved locations that were initially planned.

14

All of QEP's proved undeveloped reserves at December 31, 2017, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves. QEP removes reserves associated with a PUD location from reported proved reserves if such location is scheduled, under the then-current development plan, to be drilled later than five years from the date that such location was first reported as PUD. QEP's five-year development plan generally does not contemplate a uniform (i.e. 20% per year) conversion of PUD reserves in all of its producing regions, and PUD reserve conversion rates will likely differ by producing region.

At December 31, 2017, QEP estimates that its future development costs relating to the development of PUD reserves are approximately $486.5 million in 2018, $710.0 million in 2019, and $1,006.2 million in 2020. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. QEP believes cash flow from operations and availability under its revolving credit facility will be sufficient to cover these estimated future development costs. In addition, QEP estimates that its future development costs relating to wells waiting on completion and its refracturing program, which are not classified as PUD, are approximately $132.6 million in 2018.

Revisions to previous estimates. Revisions to previous estimates reflect our ongoing evaluation of our asset portfolio. In 2017, our PUD reserves decreased by 26.3 MMboe due to the positive and negative factors summarized in the table below:

	2017
	(MMboe)
Revisions due to:
Changes in year-end prices (price impact to January 1, 2017 balance)	7.8
Positive performance	17.7
Change in development plans	(39.5	)
Removal due to five year SEC rule	(8.7	)
Other	(3.6	)
Total revisions to prior estimates	(26.3	)

In 2017, PUD reserves were revised downward by 26.3 MMboe primarily due to negative revisions from changes in development plans (39.5 MMboe) primarily as a result of changing from a vertical well development plan to a horizontal development plan in the Uinta Basin and increased number of longer laterals in Haynesville/Cotton Valley. These negative revisions related to changes in development plans are partially offset by positive revisions related to additional increased density locations in the Haynesville/Cotton Valley and the Williston Basin. The 17.7 MMboe positive performance revision is primarily from Haynesville/Cotton Valley's successful refracturing program. In addition, QEP removed 8.7 MMboe of PUD reserves that were no longer in our 2018 forecasted capital expenditure plan and will not be drilled and completed within five years of the initial date of booking of the reserves.

Extensions and Discoveries. Extensions and discoveries in 2017 were primarily in the Permian Basin and related to new well completions and associated new PUD locations.

Purchase of Reserves in Place. Purchase of reserves in place in 2017 was primarily related to the 2017 Permian Basin Acquisition and various other acquired oil and gas properties as discussed in Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K.

Sale of Reserves in Place. Sale of reserves in place in 2017 was primarily related to the Pinedale Divestiture as discussed in Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K.

Additional Disclosures

Refer to Note 14 – Supplemental Oil and Gas Information (unaudited) in Item 8 of Part II of this Annual Report on Form 10-K for additional information pertaining to QEP's proved reserves as of the end of each of the last three years.

In addition to this filing, QEP will file reserve estimates as of December 31, 2017, 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 only for 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.

15

Third Party Reserve Reports

The Company retained Ryder Scott Company, L.P. (RSC), independent oil and gas reserve evaluation engineering consultants, to prepare the estimates of all of its proved reserves as of December 31, 2017 and 2016, and retained RSC and DeGolyer and MacNaughton (D&M) to prepare the estimates of all of its proved reserves as of December 31, 2015. RSC prepared approximately 90% and D&M prepared approximately 10% of the Company's total net proved reserves as of December 31, 2015.

Qualifications of Technical Person Preparing Reserve Reports

The individual at RSC who was responsible for overseeing the preparation of QEP's reserve estimates as of December 31, 2017, is a registered Professional Engineer in the State of Colorado and graduated with a Master's 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. A more detailed letter, including such individual's professional qualifications, has been filed as part of Exhibit 99.1 to this report.

The individual at QEP responsible for ensuring the accuracy of the reserve estimate preparation material provided to RSC and reviewing the estimates of reserves received from RSC is QEP's Director of Corporate Reserves. This individual is a member of the Society of Petroleum Engineers and graduated with a Bachelor's of Science degree in Engineering from the University of Minnesota. This individual has over 30 years of experience in the petroleum industry, including 15 years of experience in corporate reserves management.

Technologies Used

To estimate 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 and volumetric methods.

All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. Volumetric measures are then used, when available, to further corroborate these reserve estimates. Performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical production data available through late 2017, in those cases where such data were considered to be definitive. For wells currently producing, 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.

In 2017, all of QEP's proved developed non-producing and undeveloped reserves included in this Annual Report on Form 10-K were estimated by analogy to offset producing wells. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by QEP. Wells or locations that are not currently producing may start producing earlier or later than anticipated in these estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, 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.

Internal Controls Over Proved Reserve Estimates

At the end of each year, management develops a five-year capital expenditure plan based on QEP's best available data at the time the plan is developed. The Company's capital expenditure plan includes a development plan for converting PUD reserves. The development plan includes only PUD reserves that the Company is reasonably certain will be drilled within five years of booking based upon management's evaluation of a number of qualitative and quantitative factors, including estimated risk-based returns; estimated well density; current commodity pricing and cost forecasts consistent with SEC guidelines; recent drilling and re-stimulated well results; availability of services, equipment, supplies and personnel; seasonal weather; and changes in drilling and completion techniques and technology. This process is intended to ensure that PUD reserves are only claimed for locations where a final investment decision has been made by the Company.

16

QEP maintains a Reserves Review Committee comprised of members of QEP's management team and the Company's Director of Corporate Reserves. The Reserves Review Committee meets on a semi-annual basis, including prior to the filing of reserves estimates with the SEC and any public disclosure of reserve estimates. The Reserves Review Committee reviews data that is submitted by the Director of Corporate Reserves to RSC, including cost and pricing assumptions and reserve reconciliations from the previous reserve determinations. The Director of Corporate Reserves' Annual Reserve Summary Report and the Reserve Committee's Certification are provided to the Audit Committee annually. The Audit Committee also meets annually with RSC to review the reserves estimation reporting process and disclosures. QEP's Board of Directors (Board) annually reviews the Company's five-year capital expenditure plan and approves the capital budget for the first year of the development plan.

Management reviews and revises the development plan throughout the year and may modify the development plan after evaluating a number of factors, including operating and drilling results; current and expected future commodity prices; estimated risk-based returns; estimated well density; advances in technology; cost and availability of services, equipment, supplies and personnel; acquisition and divestiture activity; and our current and projected financial condition and liquidity. Management reviews changes to the development plan with the Audit Committee and the Board quarterly. Changes in the development plan are also considered by management, the Director of Corporate Reserves and the Reserves Review Committee when reserves are estimated at year-end. If there are changes that result in certain PUD reserves no longer being scheduled for development within five years from the date of initial booking, QEP reclassifies those PUD reserves to non-proved reserve categories. In addition, PUD locations and reserves may be removed from the development plan ahead of their five-year life expiration as a result of asset divestitures and acquisitions and associated changes in the priority of development within QEP's portfolio of assets.

Production, Prices and Production Costs

The following table sets forth the production volumes and field-level prices of oil, gas and NGL produced, and the related production costs, for the years ended December 31, 2017, 2016 and 2015:

	Year Ended December 31,
	2017		2016		2015
Production volumes
Oil (Mbbl)	19,620.7		20,293.8		19,582.3
Gas (Bcf)	168.9		177.0		181.1
NGL (Mbbl)	5,367.3		5,978.8		4,704.3
Total equivalent production (Mboe)	53,144.9		55,780.2		54,462.1
Total equivalent production (Bcfe)	318.9		334.7		326.8
Average field-level price (1)
Oil (per bbl)	$	47.88	$	37.90	$	42.59
Gas (per Mcf)	$	2.92	$	2.36	$	2.59
NGL (per bbl)	$	20.85	$	13.97	$	16.98
Production costs (per Boe)
Lease operating expense	$	5.55	$	4.03	$	4.38
Transportation and processing costs	4.61		5.18		5.35
Production and property taxes	2.15		1.70		2.16
Total production costs	$	12.31	$	10.91	$	11.89

____________________________

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

17

A summary of oil production by major geographical area is shown in the following table:

	Year Ended December 31,			Change
	2017	2016	2015	2017 vs 2016		2016 vs 2015
Oil production volumes (Mbbl)
Northern Region
Williston Basin	12,353.5	14,658.6	14,871.8	(2,305.1	)	(213.2	)
Pinedale	403.8	670.9	716.6	(267.1	)	(45.7	)
Uinta Basin	656.8	774.2	848.6	(117.4	)	(74.4	)
Other Northern	114.2	141.9	186.5	(27.7	)	(44.6	)
Southern Region
Permian Basin	6,060.9	3,983.9	2,791.2	2,077.0		1,192.7
Haynesville/Cotton Valley	26.5	28.4	33.6	(1.9	)	(5.2	)
Other Southern	5.0	35.9	134.0	(30.9	)	(98.1	)
Total production	19,620.7	20,293.8	19,582.3	(673.1	)	711.5

A summary of gas production by major geographical area is shown in the following table:

	Year Ended December 31,			Change
	2017	2016	2015	2017 vs 2016		2016 vs 2015
Gas production volumes (Bcf)
Northern Region
Williston Basin	15.5	15.2	11.3	0.3		3.9
Pinedale	51.9	82.4	87.5	(30.5	)	(5.1	)
Uinta Basin	16.8	22.4	22.7	(5.6	)	(0.3	)
Other Northern	5.7	7.9	9.4	(2.2	)	(1.5	)
Southern Region
Permian Basin	6.0	5.3	4.4	0.7		0.9
Haynesville/Cotton Valley	72.9	43.4	43.2	29.5		0.2
Other Southern	0.1	0.4	2.6	(0.3	)	(2.2	)
Total production	168.9	177.0	181.1	(8.1	)	(4.1	)

A summary of NGL production by major geographical area is shown in the following table:

	Year Ended December 31,			Change
	2017	2016	2015	2017 vs 2016		2016 vs 2015
NGL production volumes (Mbbl)
Northern Region
Williston Basin	3,206.1	3,182.7	1,953.4	23.4		1,229.3
Pinedale	811.0	1,417.1	1,528.6	(606.1	)	(111.5	)
Uinta Basin	152.0	203.9	287.6	(51.9	)	(83.7	)
Other Northern	13.4	22.3	19.6	(8.9	)	2.7
Southern Region
Permian Basin	1,168.5	1,109.9	815.4	58.6		294.5
Haynesville/Cotton Valley	16.2	28.2	28.6	(12.0	)	(0.4	)
Other Southern	0.1	14.7	71.1	(14.6	)	(56.4	)
Total production	5,367.3	5,978.8	4,704.3	(611.5	)	1,274.5

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A summary of oil equivalent total production by major geographical area is shown in the following table:

	Year Ended December 31,			Change
	2017	2016	2015	2017 vs 2016		2016 vs 2015
Total production volumes (Mboe)
Northern Region
Williston Basin	18,140.0	20,370.0	18,709.6	(2,230.0	)	1,660.4
Pinedale	9,871.7	15,826.0	16,829.6	(5,954.3	)	(1,003.6	)
Uinta Basin	3,605.4	4,714.3	4,924.0	(1,108.9	)	(209.7	)
Other Northern	1,082.4	1,491.7	1,764.1	(409.3	)	(272.4	)
Southern Region
Permian Basin	8,227.2	5,976.7	4,332.5	2,250.5		1,644.2
Haynesville/Cotton Valley	12,188.7	7,285.5	7,268.0	4,903.2		17.5
Other Southern	29.5	116.0	634.3	(86.5	)	(518.3	)
Total production	53,144.9	55,780.2	54,462.1	(2,635.3	)	1,318.1

A regional comparison of average field-level prices and average production costs per Boe is shown in the following table:

	Year Ended December 31,						Change
	2017		2016		2015		2017 vs 2016			2016 vs 2015
Average field-level oil price (per bbl)
Northern Region	$	47.24	$	36.97	$	41.78	$	10.27		$	(4.81	)
Southern Region	$	49.30	$	41.68	$	47.16	$	7.62		$	(5.48	)
Average field-level oil price	$	47.88	$	37.90	$	42.59	$	9.98		$	(4.69	)
Average field-level gas price (per Mcf)
Northern Region	$	2.93	$	2.33	$	2.58	$	0.60		$	(0.25	)
Southern Region	$	2.92	$	2.42	$	2.60	$	0.50		$	(0.18	)
Average field-level gas price	$	2.92	$	2.36	$	2.59	$	0.56		$	(0.23	)
Average field-level NGL price (per bbl)
Northern Region	$	21.41	$	14.50	$	18.06	$	6.91		$	(3.56	)
Southern Region	$	18.87	$	11.75	$	12.49	$	7.12		$	(0.74	)
Average field-level NGL price	$	20.85	$	13.97	$	16.98	$	6.88		$	(3.01	)
Lease operating and transportation and processing costs (per Boe)
Northern Region	$	11.24	$	8.71	$	8.67	$	2.53		$	0.04
Southern Region	$	9.52	$	10.79	$	13.41	$	(1.27	)	$	(2.62	)
Average lease operating and transportation and processing costs	$	10.16	$	9.21	$	9.73	$	0.95		$	(0.52	)

Northern Region

Williston Basin

Production volumes decreased 11% to 18,140.0 Mboe during 2017 compared to 2016, due to a decrease in oil production, which was primarily related to reduced drilling and completion activity during 2017, certain operational issues, under performance of certain wells, and producing well shut-ins associated with offset completion activity. The oil production decrease was partially offset by increased gas and NGL production, which was primarily attributable to higher allocated gas recovery as a result of restructuring a contract with a midstream provider starting in late 2016 and continuing in 2017.

19

Production volumes increased 9% to 20,370.0 Mboe during 2016 compared to 2015, due to increased gas and NGL production, which was primarily attributable to additional ethane recovered combined with higher gas recovery from a midstream provider in 2016. These increases were partially offset by a decrease in oil production volumes due to fewer net well completions in 2016 compared to 2015.

During the years ended December 31, 2017, 2016 and 2015, Williston Basin production represented 34%, 37% and 34%, respectively, of QEP's total equivalent production.

Pinedale

Production volumes decreased 38% to 9,871.7 Mboe during 2017 compared to 2016, primarily due to the divestiture of the Pinedale properties in September 2017 and reduced completion activity.

Production volumes decreased 6% to 15,826.0 Mboe during 2016 compared to 2015. Despite improved results from wells drilled and completed in 2016, production volumes decreased primarily as a result of fewer net well completions due to a decreased rig count in Pinedale in 2016 compared to 2015.

During the years ended December 31, 2017, 2016 and 2015, Pinedale production represented 19%, 28% and 31%, respectively, of QEP's total equivalent production.

Uinta Basin

Production volumes decreased 24% to 3,605.4 Mboe during 2017 compared to 2016, primarily attributable to declining gas production from existing wells and reduced completion activity in 2017. QEP did not complete any wells in the Uinta Basin in 2017.

Production volumes decreased 4% to 4,714.3 Mboe during 2016 compared to 2015, primarily due to decreased gas production from decreased net well completions in 2016 compared to 2015. QEP did not have an operated rig in the Uinta Basin for the majority of 2016.

During the years ended December 31, 2017, 2016 and 2015, Uinta Basin production represented 7%, 8% and 9%, respectively, of QEP's total equivalent production.

Other Northern

Production volumes decreased 27% to 1,082.4 Mboe during 2017 compared to 2016, primarily due to the divestiture of properties during 2017.

Production volumes decreased 15% to 1,491.7 Mboe during 2016 compared to 2015, primarily due to a decrease in gas production on Wyoming properties.

During the year ended December 31, 2017, Other Northern production represented 2% of QEP's total equivalent production, compared to 3% for the years ended December 31, 2016 and 2015, respectively.

Southern Region

Permian Basin

Production volumes increased 38% to 8,227.2 Mboe during 2017 compared to 2016, primarily as a result of continued horizontal development activities in the Spraberry Shale and Wolfcamp formations. QEP began 2017 with three operated drilling rigs in the Permian Basin and ended 2017 with six operated drilling rigs.

Production volumes increased 38% to 5,976.7 Mboe during 2016 compared to 2015, primarily due to continued horizontal development drilling, primarily in the Spraberry Shale, despite fewer net well completions in 2016 compared to 2015.

During the years ended December 31, 2017, 2016 and 2015, Permian Basin production represented 15%, 11%, and 9% respectively, of QEP's total equivalent production.

Haynesville/Cotton Valley

Production volumes increased 67% to 12,188.7 Mboe during 2017 compared to 2016, due to a well refracturing program that began in 2016 and continued throughout 2017 combined with two new well completions in 2017, partially offset by natural production decline. A QEP-operated drilling rig arrived at the end of the third quarter 2017 and remained active through the end of 2017.

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Production volumes slightly increased to 7,285.5 Mboe during 2016 compared to 2015, due to refracturing of wells and increased non-operated production, partially offset by a natural decline and the continued suspension of QEP's operated drilling program.

During the year ended December 31, 2017, Haynesville/Cotton Valley's production represented 23% of QEP's total equivalent production, compared to 13% for the years ended December 31, 2016 and 2015, respectively.

Other Southern

Production volumes decreased 75% to 29.5 Mboe during 2017 compared to 2016, due to the continued divestiture of properties.

Production volumes decreased 82% to 116.0 Mboe during 2016 compared to 2015, due to the continued divestiture of properties.

During the year ended December 31, 2015, Other Southern production represented 1% of QEP's total equivalent production.

Productive Wells

The following table summarizes the Company's operated and non-operated productive wells as of December 31, 2017, all of which are located in the U.S.:

	Oil		Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Northern Region
Williston Basin	893	362.0	—	—	893	362.0
Pinedale(1)	—	—	—	—	—	—
Uinta Basin	1,557	210.3	763	567.0	2,320	777.3
Other Northern	29	13.4	109	58.9	138	72.3
Southern Region
Permian Basin	626	590.2	—	—	626	590.2
Haynesville/Cotton Valley	1	0.1	857	506.9	858	507.0
Other Southern	1	—	58	4.0	59	4.0
Total productive wells	3,107	1,176.0	1,787	1,136.8	4,894	2,312.8

____________________________

⁽¹⁾  As a result of the Pinedale Divestiture, QEP no longer owns operated or non-operated productive wells in Pinedale as of December 31, 2017 (Refer to Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K for more information).

Although many wells produce both oil and gas, and many gas wells also have allocated NGL volumes from gas processing, a well is categorized as either an oil well or a gas well based upon the ratio of oil to gas produced at the wellhead. Additionally, each 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.

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Leasehold Acreage

The following table summarizes developed and undeveloped leasehold acreage in which the Company owns a working interest or mineral interest as of December 31, 2017. "Undeveloped Acreage" includes leasehold interests that already may have been classified as containing proved undeveloped reserves and unleased mineral interest acreage owned by the Company. Excluded from the table is acreage in which the Company's interest is limited to royalty, overriding royalty and other similar interests. All leasehold acres are located in the U.S.

	Developed Acres(1)		Undeveloped Acres(2)		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Colorado	168,348	113,540	75,549	17,129	243,897	130,669
Kansas	47,233	20,879	35,543	12,830	82,776	33,709
Louisiana	70,303	62,982	1,231	1,302	71,534	64,284
Montana	38,337	14,852	331,005	58,315	369,342	73,167
New Mexico	7,620	4,211	24,651	2,476	32,271	6,687
North Dakota	208,367	69,861	166,560	54,040	374,927	123,901
South Dakota	40	40	203,330	107,551	203,370	107,591
Texas	50,441	39,573	22,657	17,279	73,098	56,852
Utah	174,242	134,038	184,444	104,037	358,686	238,075
Wyoming	87,274	54,660	93,809	56,279	181,083	110,939
Other	15,435	4,207	157,822	43,517	173,257	47,724
Total	867,640	518,843	1,296,601	474,755	2,164,241	993,598

____________________________

⁽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 covering the acreage 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,
2018	13,867	12,024
2019	9,260	7,356
2020	7,868	7,228
2021	7,126	6,969
2022 and later	19,187	18,468
Total	57,308	52,045

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Drilling Activity

The following table summarizes the total number of development and exploratory wells drilled (defined to include the number of wells completed at any time during the applicable year, regardless of when drilling was initiated), including both operated and non-operated wells, during the years indicated.

	Development Wells				Exploratory Wells
	Productive		Dry		Productive		Dry
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Year Ended December 31, 2017
Northern Region
Williston Basin	55	28.2	—	—	—	—	—	—
Pinedale	20	8.6	—	—	—	—	—	—
Uinta Basin	—	—	—	—	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Permian Basin	65	65.0	—	—	1	0.7	—	—
Haynesville/Cotton Valley	14	2.8	—	—	—	—	—	—
Other Southern	—	—	—	—	—	—	—	—
Total	154	104.6	—	—	1	0.7	—	—
Year Ended December 31, 2016
Northern Region
Williston Basin	70	39.5	—	—	—	—	—	—
Pinedale	44	24.4	—	—	—	—	—	—
Uinta Basin	11	8.0	—	—	—	—	—	—
Other Northern	3	3.0	—	—	—	—	—	—
Southern Region
Permian Basin	19	18.8	—	—	1	0.7	—	—
Haynesville/Cotton Valley	15	2.6	—	—	—	—	—	—
Other Southern	—	—	—	—	—	—	—	—
Total	162	96.3	—	—	1	0.7	—	—
Year Ended December 31, 2015
Northern Region
Williston Basin	154	59.7	—	—	—	—	—	—
Pinedale	107	68.1	—	—	—	—	—	—
Uinta Basin	30	11.2	—	—	—	—	—	—
Other Northern	3	3.0	—	—	1	1.0	—	—
Southern Region
Permian Basin	38	32.5	—	—	—	—	—	—
Haynesville/Cotton Valley	24	3.2	—	—	—	—	—	—
Other Southern	4	0.1	—	—	—	—	—	—
Total	360	177.8	—	—	1	1.0	—	—

The following table presents operated and non-operated well completions for the year ended December 31, 2017:

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	Operated Completions		Non-operated Completions
	Gross	Net	Gross	Net
Northern Region
Williston Basin	33	27.8	22	0.4
Pinedale	20	8.6	—	—
Uinta Basin	—	—	—	—
Other Northern	—	—	—	—
Southern Region
Permian Basin	66	65.7	—	—
Haynesville/Cotton Valley	2	2.0	12	0.8
Other Southern	—	—	—	—

The following table presents operated and non-operated wells in the process of being drilled or waiting on completion as of December 31, 2017:

		Operated				Non-operated
	Drilling	Drilling		Waiting on completion		Drilling		Waiting on completion
	Rigs	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Williston Basin	1	2	2.0	5	4.7	—	—	7	0.1
Pinedale	—	—	—	—	—	—	—	—	—
Uinta Basin	1	1	1.0	1	1.0	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—	—
Southern Region
Permian Basin(1)	6	29	28.1	36	36.0	—	—	—	—
Haynesville/Cotton Valley	1	2	2.0	—	—	4	0.1	6	0.4
Other Southern	—	—	—	—	—	—	—	—	—

____________________________

⁽¹⁾  The gross operated drilling well count in the Permian Basin includes 18 wells for which surface casing has been set, but as of December 31, 2017, did not have a rig drilling.

Each gross well completed in more than one producing zone is counted as a single well. To reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling where practical. For example, in the Permian Basin QEP utilizes "tank-style" development, in which we drill and complete all wells in a given "tank" before any individual well is turned to production. In certain of our producing areas, wells drilled on a pad are not brought into production until all wells on the pad are drilled and cased and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the completion of wells and the commencement of production. In addition, existing wells that offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells have and continue to impact planned conversion of PUD reserves to proved developed reserves. QEP had 42 gross operated wells waiting on completion as of December 31, 2017.

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Delivery Commitments

QEP is a party to various long-term sales commitments for physical delivery of oil and gas with future firm delivery commitments as follows:

	Delivery Commitments
Period	(MMboe)
2018	12.0
Thereafter	—

These commitments are physical delivery obligations with prices based on prevailing index prices for oil and gas at the time of delivery. None of these commitments requires the Company to deliver oil or gas produced specifically from any of the Company's properties. The Company believes that its production and reserves should be adequate to meet these term sales commitments. If the Company's oil or gas production is not sufficient to satisfy its firm delivery commitments, the Company believes it can purchase sufficient volumes of oil or gas in the market at index-related prices to satisfy its commitments. See also Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Contractual Cash Obligations and Other Commitments, in this Annual Report on Form 10-K for discussion of firm transportation and storage commitments related to oil and gas deliveries.

In addition, at December 31, 2017, the Company did not have a significant amount of production from QEP's owned properties that was subject to priorities or curtailments that may affect quantities delivered to its customers, priority allocations or price limitations imposed by federal or state regulatory agencies, or any other factors beyond the Company's control that may affect its ability to meet its contractual obligations other than those discussed in Part I, Item 1A – Risk Factors, in this Annual Report on Form 10-K.

Seasonality

QEP drills and completes wells throughout the year, but adverse weather conditions can impact drilling, completion and field operations, which can impact overall production volumes. Seasonal anomalies can minimize or exaggerate the impact on these operations, while extreme weather events can materially constrain our operations for short periods of time.

Significant Customers

QEP's five largest customers accounted for 59%, 48%, and 30%, in the aggregate, of QEP's revenues for the years ended December 31, 2017, 2016 and 2015, respectively. During the year ended December 31, 2017, Shell Trading Company, Occidental Energy Marketing, Andeavor Logistics LP, BP Energy Company and Plains Marketing LP accounted for 14%, 13%, 13%, 10% and 10%, respectively, of QEP's total revenues. During the year ended December 31, 2016, Shell Trading Company, BP Energy Company and Valero Marketing & Supply Company accounted for 14%, 10% and 10%, respectively, of QEP's total revenues. During the year ended December 31, 2015, no customer accounted for 10% or more of QEP's total revenues. 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. Refer to Part I, Item 1A- Risk Factors, in this Annual Report on Form 10-K for additional discussion of QEP's competition.

Competition

QEP faces competition in every facet of its business, including the acquisition of producing leaseholds, wells and undeveloped leaseholds, the marketing of oil, gas and NGL products and the procurement of goods, services and labor. The Company's competitors include national oil companies, major integrated oil and gas companies, independent oil and gas companies, individual producers, gas marketers and major pipeline companies, as well as participants in other industries supplying energy, fuel and services to consumers.

Employees

At both December 31, 2017 and 2016, QEP had 656 employees. None of QEP's employees are represented by unions or covered by collective bargaining agreements.

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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, 2018, are listed below:

Charles B. Stanley	59	Chairman (2012 to present). President and Chief Executive Officer (2010 to present). Previous titles with Questar Corporation: 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	59	Executive Vice President and Chief Financial Officer (2010 to present). Treasurer (2010 to 2014). Chief Accounting Officer (2013 to 2014). Previous titles with Questar Corporation: Executive Vice President and Chief Financial Officer (2009 to 2010). Prior to joining Questar, Mr. Doleshek was Executive Vice President and Chief Financial Officer at Hilcorp Energy Company (2001 to 2009).
Jim E. Torgerson	54	Executive Vice President, QEP Energy (2013 to Present). Senior Vice President - Operations (2012 to 2013). Senior Vice President, Drilling and Completions (2011 to 2012). Previous titles with Questar Corporation: Vice President, Drilling and Completions (2009 to 2010); Vice President, Rockies Drilling and Completions (2005 to 2008).
Christopher K. Woosley	48	Senior Vice President and General Counsel (2017 to present). Vice President and General Counsel (2012 to 2016). Corporate Secretary (2016 to 2017). 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	54	Vice President, Human Resources (2010 to present). Prior to joining QEP, Ms. Fiala was the Director of Human Resources at Suncor Energy USA (2004 to 2010) and held a variety of Human Resources roles in Canada previously at Suncor Energy Inc. (1995-2003).
Alice B. Ley	44	Vice President, Controller and Chief Accounting Officer (2014 to present). Interim Controller (2013-2014). Director of Financial Reporting (2012 to 2013). Prior to joining QEP, Ms. Ley was an Accounting/Financial Analyst Manager at Frontier Oil Corporation (2001 to 2011).

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.

Government Regulation

QEP's business operations are subject to a wide range of local, state, tribal and federal statutes, rules, orders and regulations. The regulatory environment in which the oil and gas industry operates increases the cost of doing business and consequently affects profitability. Due to the myriad of complex federal, state, tribal and local regulations that may directly or indirectly affect QEP, 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 activities is a broad and increasingly complex area, notably including laws and regulations governing the potential 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 federal 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. In 2016, the Environmental Protection Agency (EPA) adopted various regulations specific to oil and gas exploration, production, gathering and processing, which impose air quality controls and work practices, and govern source determination and permitting requirements, and methane emissions. Additionally, many states are adopting air permitting and other air quality control regulations specific to oil and gas exploration, production, gathering and processing that are more stringent than existing requirements under federal regulations. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues.

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In June 2016, the EPA issued a Federal Implementation Plan (FIP) to implement the Federal Minor New Source Review Program on tribal lands for oil and gas production. The FIP primarily impacts QEP's operations on the Fort Berthold Reservation in the Williston Basin and on the Uintah and Ouray Indian Reservations in the Uinta Basin. The FIP creates a permit-by-rule process for minor sources that also incorporates emission limits and other requirements under various federal air quality standards, applying them to a range of equipment and processes used in oil and gas production. However, the FIP does not apply in areas of ozone nonattainment. As a result, the EPA may impose area-specific regulations in parts of the Uinta Basin identified as tribal lands that may require additional emissions controls on existing equipment as a result of expected designation of a portion of the Uinta Basin as a nonattainment area for ozone. Upon designation of the Uinta Basin as a nonattainment area under the Clean Air Act, the current FIP and its permit-by-rule process will no longer apply to the nonattainment area, and permits may take longer and be costly to obtain until the EPA finalizes a FIP specific to the Uinta Basin.

Greenhouse Gas Regulations and Climate Change Legislation. In recent years, the EPA has adopted and substantially expanded regulations for the measurement and annual reporting of carbon dioxide, methane and other greenhouse gases (GHG) emitted from certain large facilities, including onshore oil and gas production, processing, transmission, storage and distribution facilities. In addition, both houses of Congress have considered legislation to reduce emissions of GHG, and a number of states have taken, or are considering taking, legal measures to reduce emissions of GHG, primarily through the development of GHG inventories, GHG permitting and/or state or regional GHG cap and trade programs.

Bureau of Land Management Venting and Flaring Regulations. In November 2016, the Department of the Interior's Bureau of Land Management (BLM) finalized a rule regulating the venting and flaring of natural gas, leak detection, air emissions from equipment, well maintenance and unloading, drilling and completions and royalties potentially owed for loss of such emissions from oil and gas facilities producing on federal and tribal leases. Certain provisions of the final rule took effect in January 2017 while other provisions had a compliance deadline of January 2018. In December 2017, the BLM delayed the obligations to comply with certain provisions of the rule until January 2019. On February 22, 2018, a United States District Court for the Northern District of California preliminarily enjoined the BLM's decision to delay the rule's compliance obligations, requiring QEP and other operators to comply immediately with the rule.

Other BLM Regulations. In November 2016, the BLM finalized regulations that update and replace Onshore Orders No. 3 (Site Security), No. 4 (Measurement of Oil) and No. 5 (Measurement of Gas). These regulations increase compliance burdens on federal lessees and operators like QEP by requiring them to obtain numbers for all onshore points of federal royalty measurement from the BLM, adjusting recordkeeping requirements, and imposing new oil and gas measurement equipment standards, among other requirements, for production from federal and Indian leases. Although these regulations took effect in January 2017, the BLM has delayed the requirement to obtain numbers for all onshore points of federal royalty measurement.

Clean Water Act and Safe Drinking Water Act. The federal Clean Water Act and similar state laws regulate discharges of wastewater, oil, fill material, and other pollutants into regulated "waters of the United States." 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 scope of what areas constitute jurisdictional waters of the United States regulated under the Clean Water Act is currently entangled in ongoing litigation and related administrative matters that are not expected to be resolved for several years.  In the meantime, the EPA and the U.S. Army Corps of Engineers (Corps) are expected to determine the scope of such regulated areas much as they have over the last decade.  Areas regulated under comparable state laws are generally defined more broadly.  The federal Safe Drinking Water Act (SDWA) and comparable state statutes strictly regulate the disposal, treatment, and release of water produced or used during oil and gas development, including via underground injection control disposal wells.

In January 2017, the Corps issued revised and renewed streamlined general nationwide permits that are available to satisfy permitting requirements for certain work in streams, wetlands and other waters of the United States under Section 404 of the Clear Water Act and Section 10 of the Rivers and Harbors Act.  The new nationwide permits took effect in March 2017, or when certified by each state, whichever was later.  The oil and gas industry broadly utilizes nationwide permits 12, 14, and 39 for the construction, maintenance and repairs of pipelines, roads, and drill pads, respectively, and related structures in waters of the United States that impact less than a half-acre of waters of the United States and meet the other criteria of each nationwide permit.

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

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Comprehensive Environmental Response, Compensation and Liability Act of 1980. The federal 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 who contributed to the release of a "hazardous substance" into the environment. Such responsible persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances released into the environment and for damages to natural resources. Such liability is in addition to claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment, which may also be made by third parties.

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 on a person who is either a "generator" or "transporter" of hazardous waste or 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." Any repeal or modification of the oil and gas exploration and production waste 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. In December 2016, the U.S. District Court for the District of Columbia approved a consent decree between the EPA and a coalition of environmental nongovernmental organizations (ENGOs). The consent decree requires the EPA to review and determine whether it will revise the RCRA regulations for exploration and production waste to treat such waste as hazardous waste. The EPA must complete its review and make its decision regarding revision by March 2019. If the EPA chooses to revise the applicable RCRA regulations, it must sign a notice taking final action related to the new regulation by July 2021.

Hydraulic Fracturing Regulations. QEP'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 composed 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. QEP 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), and to state registries where required.

QEP obtains water for fracture stimulations from a variety of sources, including industrial water wells and surface water sources. When technically and economically feasible, QEP recycles flow-back and produced water for use in fracture stimulation, which reduces water consumption from surface and groundwater sources and reduces produced water disposal volumes. QEP also employs additional measures, when available, to protect water quality such as 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 feasible to avoid truck traffic and emissions. QEP believes that the employment of fracture stimulation technology does not present any significant additional risks other than those associated with the disposal of waste water (see Item 1A - Risk Factors for additional information) and those generally associated with oil and gas drilling, completion and production operations, such as the risk of spills, releases, discharges, accidents and injuries to persons and property.

Almost all oil and gas producing states require disclosure of the chemicals used in hydraulic fracturing and some form of reporting after a well is fractured. Some states have adopted additional requirements for hydraulic fracturing, such as notice to the surface owner or others, wellbore testing, ground water sampling, waste handling, and seismic monitoring. Other states rely for this purpose upon their existing regulatory programs for permitting wells, ensuring wellbore integrity, managing waste, and overseeing oil and gas development. States are updating legislative and regulatory requirements for hydraulic fracturing with increasing frequency. A few states have imposed moratoria on hydraulic fracturing, but QEP does not operate in those states.

Federal regulation of hydraulic fracturing is currently limited, but is evolving. The EPA has regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the SDWA, but QEP does not use diesel fuel in any of its hydraulic fracturing fluids. In recent years, the EPA adopted pretreatment standards under the Clean Water Act for hydraulic fracturing effluent, issued an advance notice of proposed rulemaking under the Toxic Substances Control Act to obtain data on hydraulic fracturing chemicals, and published a multi-year study on potential impacts to drinking water from hydraulic fracturing. In 2016, the Occupational Safety and Health Administration (OSHA) adopted employee-protection requirements regarding silica, which is used in hydraulic fracturing fluids.

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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.

Tribal Lands and Minerals. Various federal agencies within the U.S. Department of the Interior, particularly the BLM and the Bureau of Indian Affairs (BIA), along with certain Native American tribes, promulgate and enforce regulations pertaining to oil and gas operations on Native American tribal lands and minerals where QEP operates. These regulations include, but are not limited to, such matters as lease provisions, drilling and production requirements, surface use restrictions, environmental standards, royalty considerations and taxes. In March 2016, the BIA implemented regulations significantly altering the procedure for obtaining rights-of-way on tribal lands. In certain cases, these new regulations have increased the time and cost required to obtain necessary rights-of-ways for operation on tribal lands for QEP and its competitors.

Endangered Species Act and National Environmental Policy Act. To develop federal or Indian leases, QEP must obtain authorizations from federal agencies, such as drilling permits and rights-of-way. Prior to issuing such authorizations, federal agencies must comply with both the Endangered Species Act and National Environmental Policy Act (NEPA). 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. NEPA requires that federal agencies assess the direct, indirect and cumulative environmental impacts of their authorizations. This analysis 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 certain facilities to disseminate information on chemical inventories to employees as well as local emergency planning committees and emergency response departments. In January 2017, the EPA issued proposed rules to add natural gas processing facilities to the list of facilities that must report under EPCRA, which have not been finalized. The federal Occupational Safety and Health Act establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communication programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures.

Regulation of Underground Storage

QEP, through its wholly owned subsidiary Clear Creek Storage Company, LLC (Clear Creek), operates an underground gas storage facility under the jurisdiction of the FERC. 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. 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. In December 2016, the Pipeline and Hazardous Materials Safety Administration published an Interim Final Rule governing safety at underground natural gas storage facilities. The rule required adoption of American Petroleum Institute Recommended Practices for depleted reservoir storage facilities by January 2018, which was a highly compressed time frame, especially for smaller facilities like Clear Creek.

Transportation Regulations

Regulation of the Transportation and Sale of Natural Gas. The FERC regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (Natural Gas Act) and the Natural Gas Policy Act of 1978 and regulations issued under those Acts. Under the Energy Policy Act of 2005, the 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. The gathering of natural gas is exempt from FERC regulation under The Natural Gas Act (referred to as "non-jurisdictional” gatherer and gathering lines/systems).  However, there is no bright-line test for determining jurisdictional status.  In Haynesville/Cotton Valley, QEP owns, or holds interests in, a number of pipelines that it asserts are non-jurisdictional gathering lines (under FERC guidelines).  However, because there is no bright-line jurisdictional test, the distinction between non-jurisdictional gathering and FERC-regulated transmission pipelines may be the subject of disputes and litigation, and the jurisdictional status may change. QEP's gas gathering system is not currently subject to state utility regulations.

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Regulation of Interstate Crude Oil Pipelines. Some of QEP's crude oil pipelines are subject to regulation by the Texas Railroad Commission (TRRC). The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. QEP's crude oil pipelines (specifically the rates, terms and conditions for shipments) may also be subject to FERC regulation if the crude oil is transported in interstate or foreign commerce, whether by QEP's pipelines or other means of transportation (pursuant to the Interstate Commerce Act, the Energy Policy Act of 1992 and related rules).  QEP does not control the entire transportation path of all crude oil shipped on QEP's pipelines. Therefore, FERC regulation could be triggered by QEP's customers' transportation decisions.

Regulation of Pipeline Safety. QEP's pipeline operations are subject to regulation by the Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration (PHMSA), pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (NGPSA), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (HLPSA), with respect to crude oil. The NGPSA and HLPSA, as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities.

Transporting Crude Oil by Rail. QEP contracts to have crude oil from its Williston Basin properties transported by rail.In May 2015, the U.S. Department of Transportation issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on "offerors" of crude oil, including sampling, testing and certification requirements to improve classification of energy products placed into transport.

State Regulations

The states where QEP operates have promulgated extensive and complex regulations that govern oil and gas development within their respective boundaries. These regulations generally increase the cost of constructing, operating, producing and abandoning wells, and violations may result in civil penalties and affect QEP's ability to operate. The following are examples of these state regulations.

Texas. In 2014, the TRRC adopted new permit rules for injection wells to address seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the TRRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. Also in 2014, the TRRC adopted specific well integrity, casing, and cementing requirements for hydraulically fractured wells.  In 2016, the TRRC conformed administrative practices and procedures for horizontally drilled and fractured fields to those applicable to other types of development.

North Dakota. The North Dakota Industrial Commission (the NDI Commission), North Dakota's chief energy regulator, issued an order in June 2014 to reduce the volume of natural gas flared from oil wells in the Bakken and Three Forks formations. In connection with that order, the NDI Commission required 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 are imposed on certain wells that cannot meet the capture goals. In addition, pursuant to Commission Order No. 25417 we are required to condition crude oil produced in the Bakken Petroleum System to remove lighter, volatile hydrocarbons and reduce the vapor pressure of crude oil.

Utah. Utah's Department of Environmental Quality (UDEQ) has experienced significant delays and backlogs in the processing of air permits for oil and gas activities. Further, UDEC was concerned there were hundreds of non-compliant oil and gas facilities in operation. To address these issues, the Utah Air Quality Board voted to approve a new Permit by Rule (PBR) proposed by the Utah Division of Air Quality (UDAQ) in January 2018. The PBR (proposed September 6, 2017) requires emission controls for tanks, dehydrators and tank truck loading operations, as well as leak detection and repair and engine requirements for new sources and existing sources above specific emission thresholds. The PBR also mandates an emission source registration and triennial emissions inventory. In 2016, Utah's Governor and the Ute Tribe made recommendations to the EPA regarding the designation of a portion of the Uinta Basin as nonattainment for the eight-hour ozone National Ambient Air Quality Standard. In December 2017, the EPA responded to Utah and the Ute Tribe's nonattainment recommendation for the Uinta Basin and indicated that the EPA intends to expand the recommended nonattainment area in the Uinta Basin to include portions of five counties (including both state and tribal land) by the end of April 2018. That designation will likely result in further scrutiny of air quality permitting and additional control of emissions through the permitting programs applicable to QEP, as implemented by the UDEQ and EPA.

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Other Regulations

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 certain 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.

Reporting and Payment of Federal Royalties. The Department of Interior, Office of Natural Resources Revenue (ONRR), is responsible for collecting royalties on gas produced from Federal and Indian lands. In August 2016, the ONRR revised its civil penalty regulations, making it easier for the ONRR to issue civil penalties for incorrectly reporting production and incorrectly paying royalties on federal and tribal leases.

U.S. Tax Reform Legislation. On December 22, 2017 the Tax Cuts and Jobs Act (H.R.1) (Tax Legislation) was signed into law, which resulted in significant changes to U.S. federal income tax law. QEP expects that these changes will positively impact QEP's future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate of 21% compared to 35%. The Tax Legislation also repeals the corporate alternative minimum tax (AMT). Several provisions of the new tax law such as limitations on the deductibility of interest expense and certain executive compensation and the inability to use Section 1031 like-kind exchanges for assets such as machinery and equipment could apply to QEP; however, we do not believe that they will materially impact QEP's financial statements. The impact of the Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made and actions the Company may take as a result of the Tax Legislation.  Additionally, guidance issued by the relevant regulatory authorities regarding the Tax Legislation may materially impact QEP's financial statements. The Company will continue to analyze the Tax Legislation to determine the full impact of the new law, on the Company's consolidated financial statements and operations.

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 oil, gas and NGL are volatile, and declines in such prices could adversely affect QEP's earnings, cash flows, asset values and stock price. Historically, oil, gas and NGL prices have been volatile and unpredictable, and that volatility is expected to continue. Volatility in oil, gas and NGL prices is due to a variety of factors that are beyond QEP's control, including:

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• changes in local, regional, domestic and foreign supply of and demand for oil, gas and NGL;

• the impact of an abundance of oil, gas and NGL from unconventional sources on the global and local energy supply;

• the level of imports and/or exports of, and the price of, foreign oil, gas 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 and storage capacity;

• domestic and global economic and political conditions;

• changes in government energy policies, including imposed price controls or product subsidies or both;

• 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) and other oil producing countries, including the ability of members of OPEC to maintain oil price and production controls;

• political and economic conditions and events in the United States and in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;

• the strength of the U.S. dollar relative to other currencies;

• weather conditions and natural disasters;

• domestic and international laws, regulations and taxes, including regulations or legislation relating to climate change, induced seismicity 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 energy sources, including coal, nuclear energy, renewables and biofuels;

• demand for electricity and natural gas used as fuel for electricity generation;

• the level of global oil, gas and NGL inventories and exploration and production activity; and

• the quality of oil and gas produced.

The long-term effect of these and other factors on the prices of oil, gas and NGL is uncertain. Prolonged or further declines in these commodity prices may have the following effects on QEP's business:

• adversely affecting QEP's financial condition and liquidity and QEP's ability to finance planned capital expenditures, borrow money, repay debt and raise additional capital;

• reducing the amount of oil, gas and NGL that QEP can produce economically;

• causing QEP to delay, postpone or cancel some of its capital projects;

• causing QEP to divest of properties to generate funds to meet cash flow or liquidity requirements;

• reducing QEP's revenues, operating income or cash flows;

• reducing the amounts of QEP's estimated proved oil, gas and NGL proved reserves;

• reducing the carrying value of QEP's oil and gas properties due to recognizing additional impairments of proved and unproved properties;

• limiting QEP's access to, or increasing the cost of, sources of capital such as equity and long-term debt;

• additional counterparty credit risk; and

• decreasing the value of QEP's common stock.

Lower oil, gas and NGL prices or negative adjustments to oil, gas and NGL reserves may result in significant impairment charges. Lower commodity prices may not only decrease QEP's revenues, operating income and cash flows but also may reduce the amount of oil, gas and NGL that QEP can produce economically. GAAP requires QEP to write down, as a non-cash charge to earnings, the carrying value of its oil and gas properties in the event QEP has impairments. QEP is required to perform impairment tests on its assets periodically and whenever events or changes in circumstances warrant a review of its assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of its assets, the carrying value may not be recoverable, and, therefore, a write-down may be required. During the years ended December 31, 2017, 2016 and 2015, QEP recorded impairment charges of $38.1 million, $1,172.7 million and $39.3 million, respectively, on its proved properties and $29.0 million, $17.9 million and $2.0 million, respectively, on its unproved properties. QEP also recorded an impairment of $6.5 million on its underground gas storage facility during the year ended December 31, 2017 and goodwill impairment of $5.3 million, $3.7 million and $14.3 million during the years ended December 31, 2017, 2016 and 2015, respectively. Refer to Part I, Item 8, Note 1 – Summary of Significant Accounting Policies, of this Annual Report on Form 10-K for additional information.

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If forward oil prices decline from December 31, 2017 levels or we experience negative changes to the estimated reserve quantities, we have proved and unproved properties with a net book value of approximately $2.7 billion, as of December 31, 2017, at risk for impairment, primarily associated with our Williston Basin. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, the additional risk-adjusted value of probable and possible reserves associated with the properties, weighted-average cost of capital, operating cost estimates and future capital expenditure estimates.

The Company may not be able to economically find and develop new reserves. The Company's profitability depends not only on prevailing prices for oil, gas 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 unconventional 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. Failure to find or acquire additional reserves would cause reserves and production to decline materially from their current levels.

Oil and gas reserve estimates are imprecise, may prove to be inaccurate, and are subject to revision. Any significant inaccuracies in QEP's reserve estimates or underlying assumptions may negatively affect the quantities and present value of QEP's reserves. 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 property, 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% per year. QEP's cost estimates do not include any carbon pollution costs associated with climate change damages. 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. Therefore, reserve quantities may change when actual prices increase or decrease. In addition, the 10% discount factor QEP uses when calculating discounted future net cash flows in accordance with SEC disclosure rules, may not be the most appropriate discount factor that is based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general.

In addition, realization or recognition of proved undeveloped reserves will depend on QEP's development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of those reserves as proved. See Items 1 and 2. Business and Properties - Proved Reserves in this Annual Report on Form 10-K.

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 producible hydrocarbons are, in fact, present in those structures in economic quantities. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling 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.

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Shortages of qualified personnel and/or oilfield equipment and services could impact results of operations. The oil and gas industry has long suffered a skills shortage, recognized by many to be a threat to future growth. This skills shortage has been exacerbated by depressed oil and gas prices in the last three years and the resulting loss of skilled workers through layoffs in the oil and gas industry during these years. 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, will create challenges for QEP and its competitors and may cause periodic and problematic personnel shortages. In periods of high commodity prices, there have also been regional shortages of drilling rigs and other equipment. Any cost increases could impact profit margin, cash flow and operating results or restrict QEP's ability to drill wells and conduct operations.

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, gas and NGL, including:

• injuries and/or deaths of employees, supplier personnel, or other individuals;

• fire, explosions and blowouts;

• earthquakes and other natural disasters;

• aging infrastructure and mechanical problems;

• unexpected drilling conditions, including abnormally pressured formations or loss of drilling fluid circulation;

• pipe, cement or casing failures;

• equipment malfunctions and/or mechanical failure;

• theft or vandalism of oilfield equipment and supplies, especially in areas of increased activity;

• severe weather;

• plant, pipeline, railway and other facility accidents and failures;

• truck and rail loading and unloading problems;

• 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;

• security breaches, cyberattacks, piracy, or terrorist acts; and

• title problems.

QEP could incur substantial losses as a result of injury to or loss of life, pollution or other environmental damage, damage to or destruction of property or equipment, regulatory compliance investigations, fines or curtailment of operations, or attorneys' 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 QEP as the operator and certain 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 certain 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 its subcontractors and for property damage suffered by the contractor and its subcontractors.

QEP's insurance coverage may not be sufficient to cover 100% of potential losses arising as a result of the foregoing risks. QEP has limited or no coverage for certain other risks, such political risk, lost reserves, business interruption, cyber risk, earthquakes, war and terrorism. 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. QEP could sustain significant losses and substantial liability for uninsured risks. The occurrence of a significant event against which QEP is not fully insured could have a material adverse effect on its financial condition, results of operations and cash flows.

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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:

• spacing of wells to maximize production rates and recoverable reserves;

• landing the wellbore in the desired drilling zone;

• staying in the desired drilling zone while drilling horizontally through the formation;

• running casing the entire length of the wellbore;

• being able to run tools and other equipment consistently through the horizontal wellbore; and

• controlling high pressure wells.

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

• fracture stimulate the planned number of stages;

• run tools the entire length of the wellbore during completion operations;

• successfully clean out the wellbore after completion of the final fracture stimulation stage;

• prevent unintentional communication with other wells; and

• design and maintain efficient artificial lift throughout the life of the well.

QEP began testing the restimulation, or refracturing, of wells in Haynesville/Cotton Valley during 2016 and expanded the use of this technique to its Williston Basin properties during 2017. Refracturing an existing well is technically more challenging than fracturing a new well and may result in the loss of the existing producing well.

The use of new horizontal drilling and completion techniques that simultaneously develop multiple producing horizons can add complexity to field development. For example, QEP experienced delays in placing certain wells in the Permian Basin into production during 2017 due to evolution of its "tank-style" completion methodology caused shifts in completion timing.

If our drilling and completion activities do not meet our anticipated results or we are unable to execute our drilling and completion program because of capital constraints, lease expirations, limited access to gathering systems, limited takeaway capacity and/or declines in crude oil and natural gas prices, the return on our investment for certain projects may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future.

QEP has limited control over the activities on properties it does not operate. Other companies operate some of the properties in which QEP has an interest. QEP has limited ability to influence or control the operation or future development of these non-operated properties, including compliance with environmental, safety and other regulations, or the amount or timing of capital expenditures that QEP is required to fund with respect to them. The failure of an operator of QEP's wells to adequately perform operations, an operator's breach of the applicable agreements with QEP or an operator's failure to act in ways that are in QEP's best interest could reduce QEP's production and revenues. QEP's dependence on the operator and other working interest owners to complete these projects and QEP's limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of QEP's targeted returns on capital in drilling or acquisition activities, lead to unexpected future costs, or adversely affect the timing of activities.

Multi-well pad drilling may result in volatility in QEP operating results and delay conversion of PUD reserves. QEP utilizes multi-well pad drilling where practical. For example, in the Permian Basin, QEP utilizes "tank-style” development, in which we drill and complete all wells in a given "tank" before any individual well is turned to production. In other areas, QEP drills multiple wells from a single pad. Wells drilled on a pad are not brought into production until all wells on the pad are drilled and cased and the drilling rig is moved from the location. In addition, existing wells that offset newly drilled wells may be temporarily shut-in during the drilling and completion process. As a result, multi-well pad drilling delays the completion of wells and the commencement of production, which may cause volatility in QEP's operating results from period to period. Existing wells that offset new wells being completed by QEP or offset operators may also need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP's operating results from period to period. In addition, delays in completion of wells may impact planned conversion of PUD reserves to proved developed.

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Lack of availability of refining, gas processing, storage, gathering or transportation capacity will likely impact results of operations. The lack of availability of satisfactory oil, gas and NGL gathering and transportation, including trucks, railways and pipelines, gas processing, storage or refining capacity may hinder QEP's access to oil, gas and NGL markets or delay production from its wells. QEP's ability to market its production depends in substantial part on the availability and capacity of gathering, transportation, gas processing facilities, 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 gathering, transportation, gas processing or storage facilities do not exist near producing wells; if gathering, transportation, gas processing, storage or refining capacity is limited; or if gathering, transportation, gas processing 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 new regulations, and may result in additional regulations, on transportation of oil by railway. 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 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 leaseholds are subject to lease agreements that will expire over the next several years unless production is established on the acreage or on units containing the acreage or the leases are otherwise renewed or extended. Leases on oil and gas properties typically have a primary 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 or the lease is renewed or extended. If a lease expires or is not renewed before expiration, 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 may be required to write down its proved undeveloped reserve estimates if it is unable to convert those reserves into proved developed reserves within five years. SEC rules require that, subject to limited exceptions, proved undeveloped (PUD) reserves may only be classified as proved reserves if they are from locations scheduled to be drilled within five years after the date of booking. Recovery of PUD reserves requires the expenditure of significant capital and successful drilling operations.  QEP may be required to write down its PUD reserves if it is not successful in drilling PUD wells within the required five-year time frame. During 2017 and 2016, QEP removed 8.7 MMboe and 5.4 MMboe, respectively, of PUD reserves that were no longer in the 2018 and 2017 forecasted capital expenditure plans, respectively, and would not be drilled and completed within five years of the initial date of booking of the reserves. At December 31, 2017, approximately 63% of QEP's estimated proved reserves were PUD reserves. These reserve estimates reflect the Company's plans to make significant capital expenditures to convert its PUDs into proved developed reserves, requiring an estimated $4.3 billion during the five years ending December 31, 2022. The estimated development costs may not be accurate; timing to incur such costs may change; development may not occur as scheduled; and results may not be as estimated.

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 has identified and scheduled well locations to build its multi-year development plan for its existing leaseholds. These well locations represent a significant part of QEP's growth strategy. QEP's ability to drill and develop these locations is impacted by a number of uncertainties, including the ongoing review and analysis of geologic and engineering data, oil and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, potential interference between infill and existing wells, 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 potential well locations it 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.

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Renegotiation of gathering, processing and transportation agreements may result in higher costs and/or delays in selling production.Due to market conditions over the past few years, many midstream companies have attempted to renegotiate their gathering, processing and transportation agreements with their upstream counterparties. QEP has periodically been in discussions with its midstream providers. If QEP agrees to renegotiate its midstream agreements, the costs QEP pays for midstream services may increase. If QEP and any of its midstream service providers cannot agree on revised terms to these agreements, the midstream service providers may assert that continued performance of their obligations under these contracts is uneconomic and attempt to terminate or alter the agreements, which could hinder QEP's access to oil, gas and NGL markets, increase costs and/or delay completion of or production from its wells. Disputes over termination or changes to such agreements could result in arbitration or litigation, causing uncertainty about the status of the agreements and further delays.

QEP is required to pay fees to some of its midstream service providers based on minimum volumes regardless of actual volume throughput. QEP has contracts with some third-party service providers for gathering, processing and transportation services with minimum volume delivery commitments. As of December 31, 2017, QEP's aggregate long-term contractual obligation under these agreements was $392.9 million. QEP is obligated to pay fees on minimum volumes to service providers regardless of actual volume throughput. These fees could be significant and have a material adverse effect on QEP's 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 make capital expenditures or acquisitions because it is unable to obtain 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 QEP 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 oil, gas 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. At year end 2017, QEP had $89.0 million of borrowings under its unsecured revolving credit facility. In the past, QEP has utilized cash and its revolving credit facility, provided by a group of financial institutions, to meet short-term funding needs. Borrowings under its revolving credit facility incur floating interest rates. From time to time, QEP may use interest rate derivatives to manage the interest rate on a portion of its floating-rate debt. The interest rates for QEP's revolving credit facility are tied to QEP's ratio of indebtedness to consolidated EBITDA (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 QEP's results of operations.

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, 2017. QEP also has various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services, products and properties. QEP's financial commitments could have important consequences to its business, including, but not limited to, limiting QEP's ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, 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. QEP may be at a competitive disadvantage as compared to similar companies that have less debt. Higher levels of debt may make QEP more vulnerable to general adverse economic and industry conditions. Additionally, the 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 additional debt, and engage in transactions with affiliates. If commodity prices decline and QEP reduces its level of capital spending and production declines or QEP incurs additional impairment expense or the value of the Company's proved reserves declines, the Company may not be able to incur additional indebtedness and may not be in compliance with the financial covenants in its credit agreement in the future. Refer to Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations in Part II of this Annual Report on Form 10-K and Note 8 – Debt, in Item 8 of Part II of this Annual Report on Form 10-K for additional information regarding the financial covenants and our revolving credit agreement.

A downgrade in QEP's credit rating could negatively impact QEP's cost of and access to capital. As of February 2018,QEP's credit ratings are BB+ by Standard & Poor's Financial Services LLC (S&P), Ba3 by Moody's Investor Services, Inc. (Moody's) and BB by Fitch Ratings, Inc. (Fitch). A downgrade of QEP's credit rating may make it more difficult or expensive for QEP to raise capital from financial institutions or other sources and could require QEP to provide financial assurance of its performance under certain contractual arrangements and derivative agreements. In addition, a downgrade of QEP's credit ratings could result in a requirement for QEP to comply with an additional covenant under QEP's credit agreement, which could limit the amount of debt that QEP may incur.

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Failure to fund continued capital expenditures could adversely affect QEP's properties. QEP's exploration, development and acquisition activities require capital expenditures to achieve production and cash flows. Historically, QEP has funded its capital expenditures through a combination of cash flows from operations, its revolving credit facility, debt issuances, equity offerings and sales of assets. Future cash flows from operations are subject to a number of variables, such as the level of production from existing wells, prices of oil, gas and NGL, and QEP's success in finding, developing and producing new reserves.

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 oil, gas and NGL prices, and to protect cash flow and returns on capital from downward commodity price movements. QEP's derivative transactions are limited in duration, usually for periods of one to three years. QEP's derivatives portfolio may be inadequate to protect it from prolonged declines in the price of oil or natural gas. To the extent the Company enters into commodity derivative transactions, it may forgo some or all of the benefits of commodity price increases. 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 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 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 and joint working interest owners. This counterparty credit risk is heightened during times of economic uncertainty, tight credit markets and low commodity prices. 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 or collection issues in QEP receiving proceeds from commodity sales or reimbursement of joint venture costs. Credit enhancements, such as parental guarantees, letters of credit 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 monitors creditworthiness of its trade creditors, joint venture partners, derivative counterparties and financial institutions on an ongoing basis. However, if one of them were to experience a sudden change in liquidity, it could impair such a party's ability to perform under the terms of QEP's contracts. QEP is unable to predict sudden changes in creditworthiness or ability of these parties to perform and could incur significant financial losses.

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse impact on QEP's ability to use derivative instruments to reduce the effect of commodity price volatility and other risks associated with its business. The Dodd-Frank Act, which was signed into law in July 2010, contains significant derivatives regulation, including, among other items, a requirement that certain transactions be cleared on exchanges as well as collateral or "margin" requirements for certain uncleared swaps. The Dodd-Frank Act provides for an exception from these clearing requirements for commercial end-users, such as QEP. 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. 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. The rulemaking and implementation process are ongoing and the ultimate effect of the adopted rules and regulations and any future rules and regulations on QEP's business remains uncertain.

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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 ENGOs 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, ENGOs and other 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 gathering, processing or pipeline facilities;

• more stringent 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;

• reduced access to water supplies or restrictions on water disposal;

• increased severance and/or other taxes;

• cyberattacks;

• legal challenges or lawsuits;

• negative publicity about QEP;

• disinvestment and other targeted activist shareholder campaigns;

• increased costs of doing business;

• reduction in demand for QEP's production;

• other adverse effects on QEP's ability to develop its properties and increase production;

• increased regulation of rail transportation of crude oil;

• opposition to the construction of new oil and gas pipelines;

• postponement of state oil and gas lease sales; and

• delays in or challenges to issuance of federal oil and gas leases.

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, which could have a material adverse effect on its business, financial condition and results of operations.

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 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;

• acquiring or increasing access to gathering, processing and transportation services and capacity;

• marketing its oil, gas 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 ability to execute its strategy, QEP's financial condition and its results of operations.

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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 operations, such as QEP's 2017 Permian Basin Acquisition. 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:

• incorrect estimates or assumptions about reserves, exploration potential or potential drilling locations;

• incorrect assumptions regarding future revenues, including future commodity prices and differentials, or regarding

future development and operating costs;

• difficulty integrating the operations, systems, management and other personnel and technology of the acquired business or assets 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; result in additional liabilities, investigations and litigation; harm QEP's strategy; 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 agreement 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 agreement also limits QEP's ability to incur certain indebtedness, which could limit QEP's ability to engage in acquisitions.

QEP may be unable to divest of assets on financially attractive terms, resulting in reduced cash proceeds. QEP is continuously evaluating the sale of certain upstream and midstream assets. QEP's success in divesting assets depends, in part, upon QEP's ability to identify suitable buyers or joint venture partners; assess potential transaction terms; negotiate agreements; and, if applicable, obtain required approvals. Various factors could materially affect QEP's ability to dispose of assets on terms acceptable to QEP. Such factors include, but are not limited to: current and forecasted commodity prices; current laws, regulations and permitting processes impacting oil and gas operations in the areas where the assets are located; covenants under QEP's credit agreement; tax impacts; willingness of the purchaser to assume certain liabilities such as asset retirement obligations; QEP's willingness to indemnify buyers for certain matters; and other factors.

In addition, QEP's credit agreement contains limitations on the amount of asset sales that it is permitted to divest each year. If QEP seeks to sell more assets than is permitted under the credit agreement and is unable to receive waivers of such restrictions, then it may be unable to divest of these assets.

QEP is involved in legal proceedings that could result in substantial liabilities and materially and adversely impact the Company's financial condition.Like many oil and gas companies, the Company is involved in various legal proceedings, including threatened claims, such as title, royalty, and contractual disputes. The cost to settle legal proceedings (asserted or unasserted) or satisfy any resulting judgment against the Company in such proceedings could result in a substantial liability or the loss of interests, which could materially and adversely impact the Company's cash flows, operating results and financial condition. 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. Current accruals may be insufficient. Legal proceedings could result in negative publicity about the Company. In addition, legal proceedings distract management and other personnel from their primary responsibilities.

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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. Violations of any laws or regulations caused by either failure of our internal controls related to regulatory compliance or failure of our employees to comply with our internal policies could result in substantial civil or criminal fines. In addition, legal enforcement may be impacted by significant incentives for whistleblowers.

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. This 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, other damages, or injunctions that could limit the scope of QEP's planned operations.

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. Additionally, in June 2016, the EPA finalized closely related rules in new Subpart OOOOa to achieve additional methane and volatile organic compound reductions from certain activities in the oil and gas industry. The new rules include, among others, new requirements for finding and repairing leaks at new well sites and "reduced emission completion" requirements for hydraulically fractured oil and gas wells. The future status of Subpart OOOOa remains uncertain given ongoing litigation and administrative regulatory actions. EPA has proposed a two-year stay of the effective dates of several requirements of Subpart OOOOa, including fugitive emission requirements, well site pneumatic pump standards, and requirements for certification of closed vent systems. The rules, however, remain in effect as of the filing of this report. The regulatory uncertainty surrounding the implementation of this rule poses some complications for QEP's operations and compliance efforts.  Additionally, many states are adopting air permitting and other air quality control regulations specific to oil and gas exploration, production, gathering and processing that are more stringent than existing requirements under federal regulations.

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Regulatory requirements to reduce gas flaring and to further restrict emissions could have an adverse effect on our operations.  Wells in the Williston Basin of North Dakota and the Permian Basin of Texas, where QEP has significant operations, produce natural gas as well as crude oil. Constraints in third party gas gathering and processing systems in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. In June 2014, the NDI Commission, North Dakota's chief energy regulator, adopted a policy to reduce the volume of natural gas flared from oil wells in the Williston Basin. The Commission requires 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 may be imposed on certain wells that cannot meet the capture goals. It is possible that other states will require gas capture plans in the future to reduce flaring. Additionally, in November 2016, the Bureau of Land Management (BLM) finalized a new rule related to further controls on the venting, flaring and emissions of natural gas on BLM and tribal leases (the 2016 Venting and Flaring Rule). The rule took effect in January 2017. Some provisions of the rule required compliance in January 2017, including the royalty provisions, while other provisions including those related to further controls on the venting and flaring of natural gas, did not require compliance until January 2018. The 2016 Venting and Flaring Rule is the subject of active litigation in the U.S. District Court for the District of Wyoming. In December 2017, the BLM published a rule to delay the January 2018 compliance deadlines and suspend the obligation to comply with certain provisions that had required compliance in January 2017, until January 2019 (2017 Delay Rule). Certain states and ENGOs filed litigation in the U.S. District Court for the Northern District of California challenging the 2017 Delay Rule, and the court preliminarily enjoined the 2017 Delay Rule on February 22, 2018, requiring operators to immediately comply with the 2016 Venting and Flaring Rule. These state and federal gas capture requirements, and any similar future obligations in North Dakota or our other locations, increase our operational costs and may restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.

Rules regarding crude oil shipments by rail may pose unique hazards that may have an adverse effect on our operations. The North Dakota Industrial Commission requires that crude oil produced in the Bakken Petroleum System be conditioned to remove lighter, volatile hydrocarbons and improve the marketability and safe transportation of the crude oil. The U.S. Department of Transportation rule regarding the safe transportation of flammable liquids by rail imposes certain requirements on "offerors" of crude oil, including sampling, testing, and certification requirements. 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 species and 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 threatened and endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species as threatened or endangered in areas where we operate 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 adverse effect on our ability to develop and produce our reserves. For example, the Department of the Interior's Fish and Wildlife Service (FWS) plans to issue a proposed rule listing the Lesser Prairie-Chicken as a threatened or endangered species. The Lesser Prairie-Chicken is a grouse species native to Texas, including parts of the Permian Basin where QEP operates. Additionally, the FWS released a proposed rule to list the Louisiana Pine Snake as threatened under the Endangered Species Act (ESA). They listed Bienville Parish as one of the Parishes that the snake can be found. QEP operates within Bienville Parish. The FWS is in the process of making a final determination in 2018 of whether to list under the ESA.

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 federal Clean Air Act, Clean Water Act, 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 ENGOs to oppose drilling on some of QEP's federal and state leases. These organizations 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.

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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. 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. In addition, the BIA implemented final regulations in March 2016, which significantly altered the procedure for obtaining rights-of-way on tribal lands. These new regulations may increase the time and cost required to obtain necessary rights-of-ways for QEP's operations on tribal lands.

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 oil and gas well design and operation. The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the SDWA and issued guidance related tothis asserted regulatory authority. The EPA may consider seeking to further regulate hydraulic fracturing fluids and/or the components of those fluids. At the state level, some states have adopted and other states have considered adopting regulations and moratoria that could restrict or prohibit hydraulic fracturing in certain circumstances. If 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.

In December 2016, the EPA released its final report on the potential impacts to drinking water resources from hydraulic fracturing. The study concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances. Many other recent studies and reports have examined the potential impacts of hydraulic fracturing on the public and the environment. These or future studies could result in additional regulations, which could lead to operational burdens similar to those described above.

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. In some cases, QEP may need to obtain water from new sources and transport it to drilling sites, resulting in increased costs. 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. Moreover, 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 or may cause QEP to delay, curtail or discontinue its exploration and development plans, which could have a material adverse effect on its business, financial condition, results of operations and cash flows.

Legislation or regulatory initiatives intended to address induced seismicity could restrict QEP's drilling and production activities as well as QEP's ability to dispose of produced water gathered from such activities, which could have a material adverse effect on QEP's business. State and federal regulatory agencies have focused on a possible connection between the disposal of wastewater in underground injection wells and the increased occurrence of seismic activity in certain areas, and regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity. For example, in 2015, the United States Geological Survey identified eight states, including Texas, with areas of increased rates of seismic activity that may be attributable to fluid injection or oil and natural gas extraction activities. In addition, a number of lawsuits have been filed, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in October 2014, the Railroad Commission of Texas published a new rule governing permitting or re-permitting of disposal wells that requires, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or applicant fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates the well is likely or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well.

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QEP operates injection wells and utilizes injection wells owned by third parties to dispose of large volumes of waste water associated with its drilling, completion and production operations. QEP disposes of these volumes of produced water pursuant to permits issued to QEP by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements or prohibitions on operating certain facilities, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations or the issuance of any orders or imposition of any requirements that restrict QEP's ability to use hydraulic fracturing or dispose of produced water gathered from its drilling and production activities by limiting volumes, injection pressures or rates, or producing or disposal well locations, or requiring QEP to shut down disposal wells, could have a material adverse effect on QEP's business, financial condition and results of operations.

Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce. Climate change, the costs that may be associated with its effects and the regulation of greenhouse gas (GHG) emissions have the potential to affect our business in many ways, including increasing the costs to provide our products, reducing the demand for and consumption of our products (due to changes in both costs and weather patterns) and negatively impacting the economic health of the regions in which we operate, all of which can create financial risks. In addition, if restrictions on GHG emissions significantly increase our costs to produce oil and gas, or significantly decrease demand for our products, the value of our oil and gas reserves may decrease. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. In addition, legislative and regulatory responses related to GHG emissions and climate change may result in increased operating costs, delays in obtaining air pollution and other necessary permits for new or modified facilities and reduced demand for the oil, gas 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 energy resource development. Federal, state and local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, or banning the use of gasoline or diesel powered vehicles, which may reduce demand for oil and natural gas. Further, state and local governments may pursue litigation against producers for damages allegedly resulting from climate change, similar to the lawsuits filed by the cities of San Francisco and Oakland, California, in September 2017, and the lawsuit filed by the City of New York in January 2018 against Chevron Corp., ConocoPhillips, Co., ExxonMobil Corp., Royal Dutch Shell Plc and BP p.l.c.. QEP's ability to access and develop new oil and gas reserves may also be restricted by climate change regulation, including GHG reporting and regulation.

Congress has previously considered but not adopted proposed legislation aimed at reducing GHG emissions. The EPA has adopted final regulations under the Clean Air Act for the measurement and reporting of GHG emitted from certain large facilities and, as discussed above, has adopted additional regulations at 40 C.F.R Part 60, Subparts OOOO and OOOOa, to include additional requirements to reduce methane and volatile organic compound emissions from oil and natural gas facilities. The status of Subpart OOOOa is uncertain given the ongoing litigation, administrative reconsideration and proposed action to stay portions of those rules. Additionally, in June 2014, the United States Supreme Court upheld a portion of EPA's GHG stationary source permitting program in Utility Air Regulatory Group v. EPA, but also invalidated a portion of it. The Court's holding does not prevent states from considering and adopting state-only major source permitting requirements based solely on GHG emission levels. Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations to which QEP's operations are subject.

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In December 2015, over 190 countries, including the U.S., reached an agreement in Paris (COP 21) to reduce global emissions of GHG (the Paris Agreement). The Paris Agreement provides for the cutting of carbon emissions every five years, beginning in 2023, and sets a goal of keeping global warming to a maximum limit of two degrees Celsius and a target limit of 1.5 degrees Celsius greater than pre-industrial levels. In June 2017, President Trump announced that the U.S. would initiate the formal process to withdraw from the Paris Agreement. Withdrawal will take a few years to implement due to the Paris Agreement's legal structure and language. The current state of development of ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties or domestic regulations. Following the initiation of the U.S. withdrawal from the Paris Agreement, state and local regulation efforts are expected to increase. In several of the states in which QEP operates the regulatory authorities are considering various GHG registration and reduction programs, including methane leak detection monitoring and repair requirements specific to oil and gas facilities. For example, in January 2018, UDEQ adopted additional rules that impose leak detection and repair requirements at certain oil and gas facilities in Utah. In addition, the failure of the federal government to address climate change concerns, including, for example, a protracted delay by President Trump's administration in determining its own carbon-cost estimate (i.e., the estimate of how much carbon pollution costs society via climate damages) after rejecting the $40 per ton of carbon dioxide equivalent estimate of the Obama administration, could empower ENGOs to pursue legal challenges to oil and gas drilling and pipeline projects.

Moreover, some experts believe climate change poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in precipitation and extreme weather events. In addition, warmer winters as a result of global warming could also decrease demand for natural gas. To the extent that such unfavorable weather conditions are exacerbated by climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events (such as increased frequency, duration, and severity) and the long period of time over which any changes would take place make any estimations of future financial risk to our operations caused by these potential physical risks of climate change unreliable.

Our business could be negatively affected as a result of actions of activist shareholders, and such activism could impact the trading value of our securities. Shareholders may from time to time attempt to effect changes, engage in proxy solicitations or advance shareholder proposals. Activist shareholders may make strategic proposals, suggestions or requested changes concerning our operations, strategy, management, assets or other matters. Responding to actions by activist shareholders could be costly and time-consuming, disrupting our operations and diverting the attention of our management and employees. Such activities could interfere with our ability to execute our strategic plan or realize long-term value from our assets. The perceived uncertainties as to our future direction could also make it more difficult to attract and retain qualified personnel and affect the market price and volatility of our securities.

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 could negatively impact QEP's operating results. QEP's operating 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; weather and natural disasters; changes in customers' credit ratings; competition from other forms of energy and other pipeline and storage facilities; effects of accounting policies issued periodically by accounting standard-setting bodies; and terrorist attacks or acts of war.

45

The Company's pension plans are currently underfunded and may require large contributions, which may divert funds from other uses. QEP has a closed, qualified, defined-benefit pension plan (the Pension Plan), which covers 30 active and suspended participants, or 5%, of QEP's active employees and 184 participants who are retired or were terminated and vested. Effective January 1, 2016, the Pension Plan was frozen, such that employees do not earn additional defined benefits for future services. QEP also sponsors an unfunded, nonqualified Supplemental Executive Retirement Plan (the SERP). 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, 2017 and 2016, it is estimated that QEP's pension plans were underfunded by $29.5 million and $43.1 million, respectively. The underfunded status of QEP's pension plans may require that the Company make large contributions to such plans. QEP made cash contributions of $6.0 million and $7.2 million during the years ended December 31, 2017 and 2016, respectively, to the Pension Plan and SERP and expects to make contributions of approximately $4.7 million to these pension plans in 2018. 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 exposed 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 does not maintain specialized insurance for possible losses resulting from a cyberattack on its assets that may shut down all or part of QEP's business. QEP's systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, QEP may be required to expend additional resources to continue to modify or enhance its protective measures or to investigate and remediate any information security vulnerabilities.

While QEP has experienced cyberattacks, QEP is not aware of any material losses relating to cyberattacks; however, there is no assurance that QEP will not suffer such losses in the future. In addition, as cybersecurity threats continue to evolve, QEP may expend additional resources to continue to modify or enhance its protective measures or to investigate or remediate any cybersecurity vulnerabilities.

QEP's certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, even if an acquisition or merger may be in QEP shareholders' best interests. QEP's certificate of incorporation authorizes its Board of Directors to issue preferred stock without shareholder approval. If QEP's Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire QEP. In addition, some provisions of QEP's certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of QEP, even if the transaction would be beneficial to QEP shareholders, including:

• a classified Board of Directors, with only approximately one-third of QEP's Board of Directors elected each year;

• advance notice requirements for shareholder proposals and nominations for elections to the Board of Directors to be acted upon at meetings of shareholders; and

• the inability of QEP shareholders to call special meetings or act by written consent.

In addition, Delaware law imposes restrictions on mergers and other business combinations between QEP and any holder of 15% or more of QEP's outstanding common stock. These provisions may deter hostile takeover attempts that could result in an acquisition of QEP that could have been financially beneficial to its shareholders.

46

There may be future dilution of QEP's common stock, which could adversely affect the market price of QEP's common stock. QEP is not restricted from issuing additional shares of its common stock. In the future, QEP may issue shares of its common stock to raise cash for future capital expenditures, acquisitions or for general corporate purposes. QEP may also acquire interests in other companies by using a combination of cash and its common stock or just its common stock. QEP may also issue securities convertible into, exchangeable for or that represent the right to receive its common stock. Lastly, QEP issues stock options, restricted share awards, restricted share units and performance share units to its employees and directors as part of their compensation. Any of these events will dilute QEP shareholders' ownership interest in QEP and may reduce QEP's earnings per share and have an adverse effect on the price of QEP's common stock. In addition, sales of a substantial amount of QEP's common stock in the public market, or the perception that these sales may occur, could reduce the market price of QEP's common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 3. LEGAL PROCEEDINGS

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. Item 103 of the SEC's Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that the Company reasonably believes could exceed $100,000. The matters below are disclosed pursuant to that requirement.

EPA Request for Information –In July 2015, QEP received an information request from the EPA pursuant to Section 114(a) of the Clean Air Act. The information request sought facts and data about certain tank batteries in QEP's Williston Basin operations. After timely responding to the information request, QEP met with the EPA to discuss this matter in November 2017. While no formal federal enforcement action has been commenced in connection with the tank batteries to date, QEP anticipates that resolution of this matter will likely result in monetary penalties and require QEP to incur additional capital expenditures to correct non-compliance issues.

Louisiana Department of Environmental Quality Notice of Potential Penalty –In July 2010, QEP received a Notice of Potential Penalty (NOPP) from the Louisiana Department of Environmental Quality (LDEQ) regarding the assumption of ownership and operatorship of a single facility in Louisiana prior to transferring the facility's air quality permit. In 2011, QEP completed an internal audit, which identified 424 facilities in Louisiana for which QEP both failed to submit a complete permit application and to receive approval from the department prior to construction, modification, or operation. QEP has corrected and disclosed all known instances of non-compliance to the LDEQ and is working with the department to resolve the NOPP. The LDEQ has assumed lead responsibility for enforcement of the NOPP, and may require the Company to pay a monetary penalty.

The Mabee Ranch Royalty Partnership, LP, et al. v. QEP Energy Company – On October 2, 2017, the Mabee Ranch Royalty Partnership, LP, John W. Mabee and Joseph Guy Mabee, Jr., surface and mineral owners of acreage in the Permian Basin in Martin and Andrews County, Texas, filed a petition in the District Court of Martin County, Texas, asserting that the Company (1) trespassed on the surface of their land by continuing surface operations following the alleged termination of certain surface use agreements and (2) breached various lease agreements by failing to correctly pay royalties and by allegedly using lease property to benefit off-lease operations. The suit alleges various tort and breach of contract claims and seeks actual money damages in excess of $1,000,000, plus interest, exemplary damages, court costs, and attorneys' fees, and a declaratory judgment that portions of the oil and gas leases covering the properties are void and no longer in effect.

Refer to Note 9 – Commitments and Contingencies in Item 8 of Part II of this Annual Report on Form 10-K for additional information regarding our legal proceedings.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

QEP's common stock is listed and traded on the New York Stock Exchange (NYSE:QEP). As of January 31, 2018, QEP had 5,286 shareholders of record. In February 2016, in response to lower commodity prices, the Company's Board of Directors indefinitely suspended the payment of quarterly dividends. The future declaration and payment of dividends are at the discretion of QEP's Board of Directors and the amount thereof will depend on QEP's results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other factors deemed relevant by the Company's Board of Directors.

The following table is a summary of the high and low sales price per share of QEP's common stock as reported on the NYSE as well as the dividends paid per share per quarter for 2017 and 2016:

	High price		Low price		Dividend
	(per share)
2017
First quarter	$	19.52	$	11.69	$	—
Second quarter	13.15		8.78		—
Third quarter	10.43		7.02		—
Fourth quarter	10.62		7.30		—
Total					$	—
2016
First quarter	$	14.27	$	8.54	$	—
Second quarter	20.96		13.05		—
Third quarter	20.51		16.46		—
Fourth quarter	21.12		15.53		—
Total					$	—

Stock Performance Graph

The following stock performance information is not deemed to be "soliciting material" or to be "filed" with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent QEP specifically incorporates it by reference into such a filing.

During 2017, QEP made changes to its peer group to remove Cabot Oil & Gas Corporation due to financial characteristics that became dissimilar.

QEP's previous peer group, as defined, consisted of the following companies:

Cabot Oil & Gas Corporation	Parsley Energy, Inc.
Carrizo Oil & Gas, Inc.	PDC Energy, Inc.
Cimarex Energy Company	Range Resources Corporation
Diamondback Energy, Inc.	RSP Permian, Inc.
Energen Corporation	SM Energy Company
EP Energy Corporation	Southwestern Energy Company
Laredo Petroleum, Inc.	Whiting Petroleum Corporation
Newfield Exploration Company	WPX Energy, Inc.
Oasis Petroleum Inc.

49

After the change in peer companies, QEP's 2017 peer group consisted of the following companies:

Carrizo Oil & Gas, Inc.	Parsley Energy, Inc.
Cimarex Energy Company	PDC Energy, Inc.
Diamondback Energy, Inc.	Range Resources Corporation
Energen Corporation	RSP Permian, Inc.
EP Energy Corporation	SM Energy Company
Laredo Petroleum, Inc.	Southwestern Energy Company
Newfield Exploration Company	Whiting Petroleum Corporation
Oasis Petroleum Inc.	WPX Energy, Inc.

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

• A $100 investment was made in QEP's common stock, the S&P 500 Index and the Company's old and new peer groups as of December 31, 2012, and its relative performance is tracked through December 31, 2017;

• Investment in the Company's old and new peer groups was weighted based on the stock market capitalization of each individual company within the peer group at the beginning of each period for which a return is indicated; and

• Dividends, if any, were reinvested on the relevant payment dates.

	2012		2013		2014		2015		2016		2017
QEP Resources, Inc.	$	100.00	$	101.53	$	67.16	$	44.71	$	61.43	$	31.93
S&P 500 Index – Total Returns	$	100.00	$	132.39	$	150.51	$	152.59	$	170.84	$	208.14
New Peer Group	$	100.00	$	141.62	$	99.12	$	62.86	$	96.97	$	77.67
Old Peer Group	$	100.00	$	143.99	$	102.44	$	64.39	$	97.39	$	82.50

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Recent Sales of Unregistered Securities; Purchases of Equity Securities by QEP and Affiliated Purchasers

The following repurchases of QEP shares were made by QEP in association with vested restricted stock awards withheld for taxes.

Period	Total shares purchased (1)	Weighted-average price paid per share		Total shares purchased as part of publicly announced plans or programs	Maximum value that may yet be purchased under the plans or programs
					(in millions)
October 1, 2017 – October 31, 2017	1,932	$	8.55	—	$	—
November 1, 2017 – November 30, 2017	563	$	8.42	—	$	—
December 1, 2017 – December 31, 2017	—	$	—	—	$	—

____________________________

⁽¹⁾  All of the shares purchased during the three-month period ended December 31, 2017, were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting of restricted stock grants.

In February 2018, the Board of Directors of QEP authorized the repurchase of up to $1.25 billion of the Company's outstanding shares of common stock. The timing and amount of any QEP share repurchases will be subject to available liquidity, market conditions and proceeds from the asset sales. The repurchase plan does not obligate QEP to acquire any specific number of shares and may be discontinued at any time.

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ITEM 6. SELECTED FINANCIAL DATA

Selected financial data for the five years ended December 31, 2017, is provided in the table below. Our financial results for the years ended December 31, 2016, 2015, 2014 and 2013 have been recast, in accordance with GAAP, to reflect the adoption of ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost (see footnote (6) to the table below). In addition, our financial results for the years ended December 31, 2014 and 2013 have been recast, in accordance with GAAP, to reflect the impact of the sale of substantially all of QEP's midstream business (see footnote (7) to the table below). Refer to Items 7 and 8 in Part II of this Annual Report on Form 10-K for further discussion of the factors affecting the comparability of the Company's financial data.

	Year Ended December 31,
	2017(1)(2)(3)(4)			2016(3)(4)			2015(4)			2014(4)			2013
Results of Operations	(in millions, except per share amounts)
Revenues(5)	$	1,622.9		$	1,377.1		$	2,018.6		$	3,293.2		$	2,685.1
Operating income (loss)(6)	101.5			(1,600.7		)	(364.5		)	(840.3		)	211.9
Income (loss) from continuing operations	269.3			(1,245.0		)	(149.4		)	(409.5		)	52.1
Net income from discontinued operations, net of income tax(7)	—			—			—			1,193.9			107.3
Net income (loss)(8)	269.3			(1,245.0		)	(149.4		)	784.4			159.4
Earnings (loss) per common share(8)
Basic from continuing operations	$	1.12		$	(5.62	)	$	(0.85	)	$	(2.28	)	$	0.29
Basic from discontinued operations(7)	—			—			—			6.64			0.60
Basic total	$	1.12		$	(5.62	)	$	(0.85	)	$	4.36		$	0.89
Diluted from continuing operations(8)	$	1.12		$	(5.62	)	$	(0.85	)	$	(2.28	)	$	0.29
Diluted from discontinued operations(7)	—			—			—			6.64			0.60
Diluted total	$	1.12		$	(5.62	)	$	(0.85	)	$	4.36		$	0.89
Weighted-average common shares outstanding
Used in basic calculation	240.6			221.7			176.6			179.8			179.2
Used in diluted calculation	240.6			221.7			176.6			179.8			179.5
Dividends per common share	$	—		$	—		$	0.08		$	0.08		$	0.08
Financial Position
Total Assets at December 31,	$	7,394.8		$	7,245.4		$	8,398.2		$	9,256.4		$	9,380.4
Capitalization at December 31,
Long-term debt	2,160.8			2,020.9			2,191.5			2,187.7			2,969.0
Total equity	3,797.9			3,502.7			3,947.9			4,075.3			3,876.8
Total Capitalization	$	5,958.7		$	5,523.6		$	6,139.4		$	6,263.0		$	6,845.8
Cash Flow From Operations
Net cash provided by (used in) operating activities	$	598.4		$	663.7		$	481.3		$	1,542.5		$	1,191.7
Capital expenditures	(1,974.8		)	(1,208.1		)	(1,239.4		)	(2,726.4		)	(1,602.6		)
Net cash provided by (used in) investing activities	(1,168.0		)	(1,179.1		)	(1,217.6		)	578.2			(1,441.5		)
Net cash provided by (used in) financing activities	125.8			583.1			(47.7		)	(990.6		)	279.8
Non-GAAP Measure
Adjusted EBITDA(6)(9)	$	736.1		$	628.1		$	1,031.2		$	1,589.7		$	1,545.6

 ____________________________

⁽¹⁾  During the year ended December 31, 2017, the results are impacted by the 2017 Permian Basin Acquisition, which occurred in October 2017. Refer to Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K for detailed information on the 2017 Permian Basin Acquisition.

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⁽²⁾  During the year ended December 31, 2017, the results are impacted by the Pinedale Divestiture, which occurred in September 2017. Refer to Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K for detailed information on the Pinedale Divestiture.

⁽³⁾  During the years ended December 31, 2017 and 2016, the results are impacted by the 2016 Permian Basin Acquisition, which occurred in October 2016. Refer to Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K for additional information on the 2016 Permian Basin Acquisition.

⁽⁴⁾  During the years ended December 31, 2017, 2016, 2015 and 2014, the results are impacted by the 2014 Permian Basin Acquisition, which occurred in February 2014, and the property sales in the Other Southern area, beginning in the second quarter of 2014.

⁽⁵⁾  Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing and QEP Energy. In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and Haynesville Gathering. As a result, QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had in prior periods.

⁽⁶⁾  In the first quarter of 2017, QEP early adopted ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, which is effective retrospectively. As a result, the Company has recast operating income and Adjusted EBITDA for all prior periods shown. The Company recognizes service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of Operations and all other expenses related to the Pension Plan, SERP and Medical Plan are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations. Refer to Note 11 – Employee Benefits, in Item 8 of Part II of this Annual Report on Form 10-K for additional information.

⁽⁷⁾  In December 2014, QEP sold substantially all of QEP's midstream business. The results of operations of QEP's midstream business (excluding results of Haynesville Gathering) have been reflected as discontinued operations and results for the years ended December 31, 2014 and 2013, have been reclassified.

⁽⁸⁾  Net income for 2017 was positively impacted by a $307.9 million tax benefit, primarily due to a revaluation of our net deferred tax liability to reflect the federal rate change resulting from 35% to 21% under the new Tax Legislation.

⁽⁹⁾  Adjusted EBITDA is a non-GAAP financial measure. Management defines Adjusted EBITDA 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, loss from early extinguishment of debt and certain other items. See Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report on Form 10-K for additional disclosures related to Adjusted EBITDA.

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The following table reconciles QEP's Net Income (Loss) (a GAAP measure) to Adjusted EBITDA. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP.

	Year Ended December 31,
	2017			2016			2015			2014			2013
	(in millions)
Net income (loss)	$	269.3		$	(1,245.0	)	$	(149.4	)	$	784.4		$	159.4
Net income from discontinued operations, net of tax	—			—			—			(1,193.9		)	(107.3		)
Net income (loss) from continuing operations	269.3			(1,245.0		)	(149.4		)	(409.5		)	52.1
Interest expense	137.8			143.2			145.6			169.1			165.1
Interest and other (income) expense(1)	(1.6		)	(23.7		)	10.1			(5.8		)	(6.3		)
Income tax provision (benefit)	(312.2		)	(708.2		)	(93.6		)	(232.5		)	60.1
Depreciation, depletion and amortization	754.5			871.1			881.1			994.7			963.8
Unrealized (gains) losses on derivative contracts	(40.0		)	367.0			183.7			(374.4		)	88.7
Exploration expenses	22.0			1.7			2.7			9.9			11.9
Net (gain) loss from asset sales	(213.5		)	(5.0		)	(4.6		)	148.6			(103.5		)
Impairment	78.9			1,194.3			55.6			1,143.2			93.0
Loss from early extinguishment of debt	32.7			—			—			2.0			—
Other(1)(2)	8.2			32.7			—			—			—
Adjusted EBITDA from continuing operations	736.1			628.1			1,031.2			1,445.3			1,324.9
Adjusted EBITDA from discontinued operations	—			—			—			144.4			220.7
Adjusted EBITDA	$	736.1		$	628.1		$	1,031.2		$	1,589.7		$	1,545.6

____________________________

⁽¹⁾  In the first quarter of 2017, QEP early adopted ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, which is effective retrospectively. As a result, the Company recast "Interest and other (income) expense" and "Other" for all prior periods shown. The Company recognizes service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of Operations and all other expenses related to the Pension Plan, SERP and Medical Plan benefits are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations. Refer to Note 11 – Employee Benefits, in Item 8 of Part II of this Annual Report on Form 10-K for additional information.

⁽²⁾  Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017 and 2016. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA.

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

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. MD&A should be read in conjunction with the Consolidated Financial Statements and related Notes included in Item 8 of Part II of this Annual Report on Form 10-K and also with "Risk Factors" in Item 1A of this report.

The following information updates the discussion of QEP's financial condition provided in its 2016 Annual Report on Form 10-K filing, and analyzes the changes in the results of operations between the years ended December 31, 2017 and 2016, and between the years ended December 31, 2016 and 2015.

OVERVIEW

QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Northern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".

While historically the Company has been more natural gas weighted, in recent years the Company has increased its focus on growing its oil and NGL production. Since the beginning of 2012, the Company has made approximately $3.9 billion of acquisitions of oil-weighted properties, spent approximately 60% of its capital expenditures (excluding property acquisitions) on its oil-weighted properties, and divested gas-weighted properties, such as Pinedale. Compared to 2011, the Company's 2017 oil production has grown 424% and the Company's 2017 oil and NGL production represented 47% of total production compared to 14% in 2011. Additionally, oil and NGL revenue represented 68% of total field-level revenues during 2017 compared to 27% in 2011. Approximately 56% of total proved reserves at year-end 2017 were oil and NGL. Consistent with its emphasis on oil-weighted properties, QEP now reflects its production and reserve amounts in oil equivalent volumes rather than gas equivalent volumes. In February 2018, QEP's Board of Directors has unanimously approved several strategic initiatives including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and focus its activities in the Permian Basin.

Acquisitions and Divestitures

While QEP believes its extensive inventory of identified drilling locations provides a solid base for growth in production and reserves, the Company continues to evaluate and acquire properties in its existing areas of operations to add additional acreage and facilitate the drilling of long lateral wells. QEP believes that its experience, expertise and presence in its core operating areas, combined with its financial strength, enhances its ability to pursue acquisition opportunities. The Company continuously evaluates potential acquisition, divestiture and joint venture opportunities that align with its strategic objectives.

Acquisitions

In the fourth quarter of 2017, QEP acquired additional oil and gas properties in the Permian Basin for an aggregate purchase price of $720.7 million, subject to post-closing purchase price adjustments. The 2017 Permian Basin Acquisition consists of approximately 15,100 acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. QEP structured the transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded the purchase price with the proceeds from the sale of QEP's Pinedale assets. In addition, QEP has made offers to various persons who own additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the original purchase. If all offers are accepted, QEP now expects that the aggregate purchase price will not exceed $50.0 million. In February 2018, QEP entered into agreements related to these offers for an aggregate purchase price of $36.1 million, subject to customary purchase price adjustments. The transactions and remaining offers, if accepted, are expected to be funded with borrowings under the credit facility and are expected to close in the first half of 2018. In addition to the 2017 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2017, which primarily included undeveloped leasehold acreage, producing wells and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million.

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In October 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $591.0 million. The 2016 Permian Basin Acquisition consisted of approximately 9,600 net acres in Martin County, Texas, which are primarily held by production from existing vertical wells. The 2016 Permian Basin Acquisition was funded with cash on hand, which included proceeds from an equity offering in June 2016. In addition to the 2016 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2016, primarily in the Permian and Williston basins, for an aggregate purchase price of $54.6 million, which included additional interests in QEP operated wells and additional undeveloped leasehold acreage.

During the year ended December 31, 2015, QEP acquired various oil and gas properties, primarily in the Permian and Williston basins, for a total purchase price of $98.3 million, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage.

Divestitures

In September 2017, QEP sold its assets in Pinedale (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to post-closing purchase price adjustments, and recorded a pre-tax gain on sale of $180.4 million which was recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations. QEP also sold its Central Basin Platform assets (Central Basin Platform Divestiture) and received net cash proceeds of $3.5 million. Refer to Note 3 – Capitalized Exploratory Well Costs, in Item 8 of Part II of this Annual Report on Form 10-K for more information. In addition to the Pinedale Divestiture and the Central Basin Platform Divestiture, QEP received additional net cash proceeds of $85.1 million, primarily related to the sale of non-core properties in the Other Northern area.

In 2016, QEP sold its interest in certain non-core properties in the Other Southern area for aggregate proceeds of $29.0 million.

In 2015, QEP sold its interest in certain non-core properties in the Other Southern and Other Northern areas for aggregate proceeds of $31.7 million, of which $21.8 million was cash and $9.9 million was accounts receivable.

Financial and Operating Highlights

During the year ended December 31, 2017, QEP:

• Generated net income of $269.3 million, or $1.12 per diluted share;

• Reported $736.1 million of Adjusted EBITDA (a non-GAAP measure defined and reconciled in Item 7 of Part II of this Annual Report on Form 10-K), a 17%increase over 2016;

• Recognized realized oil prices that were $6.07 per bbl, or 14% higher compared to 2016;

• Divested assets in Pinedale for approximately $718.2 million;

• Delivered oil equivalent production of 53.1 MMboe, a 5%decrease from 2016;

• Delivered record oil production of 6.1 MMbbls in the Permian Basin, a 52%increase over 2016;

• Reported year end total proved reserves of 684.7 MMboe, including record proved crude oil reserves of 320.5 MMbbl;

• Incurred capital expenditures (excluding property acquisitions) of $1,219.8 million, a 130% increase over 2016;

• Acquired various oil and gas properties for approximately $815.2 million, of which the vast majority of which were properties in the Permian Basin;

• Expanded our successful refracturing program in Haynesville/Cotton Valley and began refracturing wells in the Williston Basin; and

• Issued $500.0 million of senior notes and repaid $445.7 million of senior notes, which were due in the next five years; paid fees and expenses associated with the repayment and used the remainder for general corporate purposes.

Outlook

Since the commodity price downturn in late 2014, the Company has focused on operating costs, per well drilling costs and managing its liquidity while continuing its transition from a natural gas weighted company to a more balanced portfolio. We believe our balance sheet and sufficient liquidity will allow us to grow oil production, primarily in the Permian Basin.

Our total capital expenditures (excluding property acquisitions), for 2018 are expected to be approximately $1,075.0 million (excluding property acquisitions), a decrease of approximately 12% from 2017 capital expenditures. We continuously evaluate our level of drilling and completion activity in light of drilling results, commodity prices and changes in our operating and development costs and will adjust our capital spending program if necessary. See "Cash Flow from Investing Activities" for further discussion of our capital expenditures.

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Factors Affecting Results of Operations

Supply, Demand, Market Risk and their Impact on Oil and Gas Prices

Oil and gas prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. In recent years, oil and gas prices have been affected by supply growth, particularly in U.S. oil and gas production, driven by advances in drilling and completion technologies, and fluctuations in demand driven by a variety of factors.

Changes in the market prices for oil, gas and NGL directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling and completion activity and related capital expenditures, our proved undeveloped (PUD) reserves conversion rate, liquidity, rate of growth, costs of goods and services required to drill, complete and operate wells, and the carrying value of its oil and gas properties. Historically, field-level prices received for QEP's oil and gas production have been volatile. During the past five years, the posted price for WTI crude oil has ranged from a low of $26.19 per barrel in February 2016 to a high of $110.62 per barrel in September 2013. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. If prices of oil, gas or NGL decline to early 2016 levels or further, our operations, financial condition and level of expenditures for the development of our oil and gas reserves may be materially and adversely affected.

NGL prices have also been affected by increased U.S. hydrocarbon production and insufficient domestic demand and export capacity. Prices of heavier NGL components, typically correlated to oil prices, have declined in concert with weakening oil prices. Concurrently, the lighter NGL components, ethane and propane, have experienced declines as a result of growing North American oversupply. In addition to commodity price movements, QEP's composite NGL prices are affected by ethane recovery or rejection. When ethane is recovered as a discrete NGL component instead of being sold as part of the natural gas stream, the average sales price of a NGL barrel decreases as the ethane price is generally lower than the prices of the remaining NGL components. As permitted in some of its processing agreements, QEP recovers ethane when gas processing economics support the recovery of ethane from the natural gas stream. When gas processing economics do not support ethane recovery, and processing agreements permit it to do so, QEP elects to reject ethane from the NGL stream. In instances where QEP can make an election, QEP rejected ethane during the year ended December 31, 2017, and assuming similar ethane and natural gas prices, plans to reject ethane during 2018.

Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the global economy, including Europe and China's economic outlook; the Organization of Petroleum Exporting Countries (OPEC) countries oil production and policies regarding production quotas; political unrest and economic issues in South America, Asia, Europe, the Middle East, and Africa; slowing growth in certain emerging market economies; actions taken by the United States Congress and the president of the United States; the U.S. federal budget deficit; changes in regulatory oversight policy; commodity price volatility; the impact of a potential increase in interest rates; volatility in various global currencies; and other factors. A dramatic decline in regional or global economic conditions, a major recession or depression, regional political instability, economic sanctions, war, or other factors beyond the control of QEP could have a significant impact on oil, gas and NGL supply, demand and prices and the Company's ability to continue its planned drilling programs and could materially impact the Company's financial position, results of operations and cash flow from operations. In December 2015, the U.S. lifted a 40-year ban on the export of oil, giving U.S. producers access to a wider market. As a result, the U.S. may in the future become a significant exporter of oil if the necessary infrastructure is built to support oil exports. Disruption to the global oil supply system, political and/or economic instability, fluctuations in currency values, and/or other factors could trigger additional volatility in oil prices.

Due to continued global economic uncertainty and the corresponding volatility of commodity prices, QEP continues to focus on a sufficient liquidity position to ensure financial flexibility. QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to partially protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. At December 31, 2017, assuming forecasted 2018 annual production of approximately 49.6 MMboe, QEP had approximately 77% of its forecasted oil production and 79% of its forecasted gas production covered with fixed-price swaps. The average swap prices for the derivative contracts could be significantly lower than the average swap prices for the derivative contracts settled in prior years and, therefore, QEP's derivative portfolio may not contribute as much to QEP's net realized prices for current and future production. See Item 7A – "Quantitative and Qualitative Disclosures about Market Risk – Commodity Price Risk Management", of Part II of this Annual Report on Form 10-K for further details concerning QEP's commodity derivatives transactions.

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Potential for Future Asset Impairments

The carrying values of the Company's properties are sensitive to declines in oil, gas and NGL prices as well as increases in various development and operating costs and expenses and, therefore, are at risk of impairment. The Company uses a cash flow model to assess its proved properties for impairment. The cash flow model includes numerous assumptions, including estimates of future oil, gas and NGL production, estimates of future prices for production that are based on the price forecast that management uses to make investment decisions, including estimates of basis differentials, future operating costs, transportation expenses, production taxes, and development costs that management believes are consistent with its price forecast, and discount rates. Management also considers a number of other factors, including the forward curve for future oil and gas prices, and developments in regional transportation infrastructure when developing its estimate of future prices for production. All inputs for the cash flow model are evaluated at each date of estimate.

We base our fair value estimates on projected financial information that we believe to be reasonably likely to occur. An assessment of the sensitivity of our capitalized costs to changes in the assumptions in our cash flow calculations is not practicable, given the numerous assumptions (e.g., future oil, gas and NGL prices; production and reserves; pace and timing of development plans; timing of capital expenditures; operating costs; drilling and development costs; and inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced oil, gas and NGL prices on future undiscounted cash flows would likely be offset by lower drilling and development costs and lower operating costs.

During the year ended December 31, 2017, the Company recorded impairments of $78.9 million primarily due to impairments of proved properties in the Other Northern area, underground gas storage facility and unproved properties in the Permian Basin. During the year ended December 31, 2016, impairments were $1,194.3 million primarily due to impairments of proved properties in Pinedale. During the year ended December 31, 2015, impairments were $55.6 million primarily due to impairments of proved properties in the Other Southern and Other Northern areas and goodwill associated with lower future prices. For additional information see Item 1A – Risk Factors in Part I and Note 1 – Summary of Significant Accounting Policies, in Item 8 of Part II of this Annual Report on Form 10-K.

If forward oil prices decline from December 31, 2017 levels or we experience negative changes in estimated reserve quantities, we have proved and unproved property with a net book value of approximately $2.7 billion, as of December 31, 2017, at risk for impairment, primarily associated with our Williston Basin. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, the additional risk-adjusted value of probable and possible reserves associated with the properties, weighted-average cost of capital, operating cost estimates and future capital expenditure estimates.

Multi-Well Pad Drilling

To reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling where practical. For example, in the Permian Basin QEP utilizes "tank-style" development, in which we drill and complete all wells in a given "tank" before any individual well is turned to production. In certain of our producing areas, wells drilled on a pad are not brought into production until all wells on the pad are drilled and cased and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the completion of wells and the commencement of production. In addition, existing wells that offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells may impact planned conversion of PUD reserves to proved developed reserves.

Uncertainties Related to Claims

QEP is currently subject to claims that could adversely impact QEP's liquidity, operating results, capital expenditures and financial condition, including, but not limited to those described in Item 3. Legal Proceedings in Part I of this Annual Report on Form 10-K. Given the uncertainties involved in these matters, QEP is unable to predict the ultimate outcomes.

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RESULTS OF OPERATIONS

Net Income

QEP generated net income during the year ended December 31, 2017, of $269.3 million, or $1.12 per diluted share, compared to a net loss of $1,245.0 million, or $5.62 per diluted share, in 2016. The increase in net income for the year ended December 31, 2017, compared to the year ended December 31, 2016, was primarily due to a decrease in impairment expense of $1,115.4 million, a $245.8 million (18%) increase in revenues (primarily oil revenue) and an increase of $257.5 million in realized and unrealized derivative gains. Net income during the year ended December 31, 2017, was also positively impacted by a $307.9 million tax benefit, primarily due to a revaluation of our net deferred tax liability to reflect the federal rate change resulting from 35% to 21% under the new tax legislation.

QEP generated a net loss during the year ended December 31, 2016, of $1,245.0 million, or $5.62 per diluted share, compared to a net loss of $149.4 million, or $0.85 per diluted share, in 2015. The increase in net loss for the year ended December 31, 2016, compared to the year ended December 31, 2015, was primarily due to an increase in impairment expense of $1,138.7 million, a 26%decrease in average realized prices, a $183.3 million increase in unrealized losses on derivative contracts and a 17%increase in general and administrative expense. These changes were partially offset by a 2%increase in oil equivalent production, a 19%decrease in production and property taxes and a 6%decrease in lease operating expense.

Adjusted EBITDA

Management defines Adjusted EBITDA 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, loss from early extinguishment of debt and certain other items. Management uses Adjusted EBITDA to evaluate QEP's financial performance and trends, make operating decisions and allocate resources. Management believes the measure is useful supplemental information for investors because it eliminates the impact of certain nonrecurring, non-cash and/or other items that management does not consider as indicative of QEP's performance from period to period. QEP's Adjusted EBITDA may be determined or calculated differently than similarly titled measures of other companies in our industry, which would reduce the usefulness of this non-GAAP financial measure when comparing our performance to that of other companies.

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Below is a reconciliation of net income (loss) (a GAAP measure) to Adjusted EBITDA. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP.

	Year Ended December 31,
	2017			2016			2015
	(in millions)
Net income (loss)	$	269.3		$	(1,245.0	)	$	(149.4	)
Interest expense	137.8			143.2			145.6
Interest and other (income) expense(1)	(1.6		)	(23.7		)	10.1
Income tax provision (benefit)	(312.2		)	(708.2		)	(93.6		)
Depreciation, depletion and amortization	754.5			871.1			881.1
Unrealized (gains) losses on derivative contracts	(40.0		)	367.0			183.7
Exploration expenses	22.0			1.7			2.7
Net (gain) loss from asset sales	(213.5		)	(5.0		)	(4.6		)
Impairment	78.9			1,194.3			55.6
Loss from early extinguishment of debt	32.7			—			—
Other(1)(2)	8.2			32.7			—
Adjusted EBITDA	$	736.1		$	628.1		$	1,031.2

____________________________

⁽¹⁾  In the first quarter of 2017, QEP early adopted ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, which is effective retrospectively. As a result, the Company recast "Interest and other (income) expense" and "Other" for all prior periods shown. The Company recognizes service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of Operations and all other expenses related to the Pension Plan, SERP and Medical Plan benefits are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations. Refer to Note 11 – Employee Benefits, in Item 8 of Part II of this Annual Report on Form 10-K for additional information.

⁽²⁾  Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017 and 2016. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA.

Adjusted EBITDA increased to $736.1 million during the year ended December 31, 2017, compared to $628.1 million in 2016, primarily due to a 15%increase in average realized prices, a 15%decrease in transportation and processing costs and a 22%decrease in general and administrative expenses. These changes were partially offset by a 5%decrease in oil equivalent production, a 31%increase in lease operating expense and a 21%increase in production and property taxes.

Adjusted EBITDA decreased to $628.1 million during the year ended December 31, 2016, compared to $1,031.2 million in 2015, primarily due to a 26%decrease in average realized prices. These changes were partially offset by a 2%increase in oil equivalent production, a 19%decrease in production and property taxes and a 6%decrease in lease operating expense.

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Revenue

Revenue, Volume and Price Variance Analysis

The following table shows volume and price related changes for each of QEP's production-related revenue categories for the year ended December 31, 2017 compared to the years ended December 31, 2016 and 2015:

	Oil			Gas			NGL			Total
Production revenues	(in millions)
Year ended December 31, 2015	$	834.2		$	468.5		$	80.0		$	1,382.7
Changes associated with volumes(1)	30.2			(10.6		)	21.6			41.2
Changes associated with prices(2)	(95.3		)	(40.8		)	(18.1		)	(154.2		)
Year ended December 31, 2016	$	769.1		$	417.1		$	83.5		$	1,269.7
Changes associated with volumes(1)	(25.5		)	(18.4		)	(8.5		)	(52.4		)
Changes associated with prices(2)	195.8			95.3			36.9			328.0
Year ended December 31, 2017	$	939.4		$	494.0		$	111.9		$	1,545.3

____________________________

⁽¹⁾  The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the years ended December 31, 2017 and 2016, as compared to the years ended December 31, 2016 and 2015, by the average field-level price for the years ended December 31, 2016 and 2015.

⁽²⁾  The revenue variance attributed to the change in price is calculated by multiplying the change in field-level prices from the years ended December 31, 2017 and 2016, as compared to the years ended December 31, 2016 and 2015, by the respective volumes for the years ended December 31, 2017 and 2016. Pricing changes are driven by changes in commodity field-level prices, excluding the impact from commodity derivatives.

A comparison of net realized average oil, gas and NGL prices, including the realized gains and losses on commodity derivative contracts, is provided in the following table:

	Year Ended December 31,							Change
	2017			2016		2015		2017 vs 2016			2016 vs 2015
Oil (per bbl)
Average field-level price	$	47.88		$	37.90	$	42.59	$	9.98		$	(4.69	)
Commodity derivative impact	0.34			4.25		18.06		(3.91		)	(13.81		)
Net realized price	$	48.22		$	42.15	$	60.65	$	6.07		$	(18.50	)
Gas (per Mcf)
Average field-level price	$	2.92		$	2.36	$	2.59	$	0.56		$	(0.23	)
Commodity derivative impact	(0.13		)	0.25		0.57		(0.38		)	(0.32		)
Net realized price	$	2.79		$	2.61	$	3.16	$	0.18		$	(0.55	)
NGL (per bbl)
Average field-level price	$	20.85		$	13.97	$	16.98	$	6.88		$	(3.01	)
Commodity derivative impact	—			—		—		—			—
Net realized price	$	20.85		$	13.97	$	16.98	$	6.88		$	(3.01	)
Average net equivalent price (per Boe)
Average field-level price	$	29.08		$	22.76	$	25.38	$	6.32		$	(2.62	)
Commodity derivative impact	(0.29		)	2.35		8.39		(2.64		)	(6.04		)
Net realized price	$	28.79		$	25.11	$	33.77	$	3.68		$	(8.66	)

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December 31, 2017 compared to December 31, 2016

Oil sales.Oil sales were $939.4 million for the year ended December 31, 2017, an increase of $170.3 million, or 22%, compared to 2016. This increase was a result of a 26%increase in average field-level prices, partially offset by a 3%decrease in oil production volumes. The increase in average field-level oil prices was driven by an increase in average NYMEX-WTI oil prices for the comparable period combined with narrowing differentials in our Northern Region properties. The 3%decrease in oil production volumes was primarily driven by a decrease in the Williston Basin due to a reduction in completion activity as well as operational issues, under performance by certain wells, and well shut-ins associated with completion activity and a decrease in Pinedale due to the Pinedale Divestiture, partially offset by an increase in the Permian Basin due to the late 2016 and 2017 acquisitions and increased completion activity.

Gas sales.Gas sales were $494.0 million for the year ended December 31, 2017, an increase of $76.9 million, or 18%, compared to 2016. This increase was a result of a 24%increase in average field-level prices, partially offset by a 5%decrease in gas production volumes. The increase in average field-level gas prices was driven by an increase in average NYMEX-HH natural gas prices for the comparable period. The 5%decrease in production volumes was primarily driven by the Pinedale Divestiture and a production decrease in the Uinta Basin due to reduced completion activity. These decreases were partially offset by increased production in Haynesville/Cotton Valley due to a well refracturing program that began in 2016 and continued throughout 2017 on QEP operated wells and two new operated well completions in 2017.

NGL sales. NGL sales were $111.9 million for the year ended December 31, 2017, an increase of $28.4 million, or 34%, compared to 2016. This increase was primarily a result of a 49%increase in average field-level prices, partially offset by a 10%decrease in NGL production volumes. The 49%increase in average field-level prices was primarily driven by an increase in propane, ethane and other NGL component prices. The 10%decrease in NGL production volumes was primarily driven by the Pinedale Divestiture and production decreases in the Uinta Basin due to reduced completion activity.

December 31, 2016 compared to December 31, 2015

Oil sales. Oil sales were $769.1 million for the year ended December 31, 2016, a decrease of $65.1 million, or 8%, compared to 2015. This decrease was a result of an 11%decrease in average field-level oil prices, partially offset by a 4%increase in oil production volumes. The decrease in average field-level oil prices was driven by a decrease in average NYMEX WTI and ICE Brent oil prices for the comparable period. The 4%increase in oil production volumes was primarily driven by an increase in the Permian Basin due to continued development drilling partially offset by a decrease in the Williston Basin due to fewer net well completions in 2016 compared to 2015.

Gas sales. Gas sales were $417.1 million for the year ended December 31, 2016, a decrease of $51.4 million, or 11%, compared to 2015. This decrease was a result of a 9%decrease in average field-level prices and a 2%decrease in gas production volumes. The decrease in average field-level gas prices was driven by a decrease in average NYMEX-HH natural gas prices for the comparable period. The 2%decrease in production volumes was primarily driven by production decreases in Pinedale due to fewer net well completions resulting from a lower rig count in 2016 compared to 2015 and in the Other Southern area due to the continued divestitures of properties. These decreases were partially offset by increased production in the Williston Basin due to higher gas recovery from a midstream provider in 2016.

NGL sales. NGL sales were $83.5 million for the year ended December 31, 2016, an increase of $3.5 million, or 4%, compared to 2015. This increase was primarily a result of a 27%increase in production volumes, partially offset by an 18%decrease in average field-level prices. The 27%increase in NGL production volumes was primarily driven by increases in the Williston and Permian basins. The increase in the Williston Basin is due to additional ethane recovered by a midstream provider and the increase in the Permian Basin is due to continued development drilling. These increases were partially offset by decreases in Pinedale due to fewer net well completions due to a lower rig count in 2016 compared to 2015 and in the Uinta Basin due to refrigeration processing of gas in 2016 compared to cryogenic processing during a portion of 2015 as well as fewer net well completions in 2016 compared to 2015. The 18%decrease in average field-level prices was driven by receiving an increased percentage of ethane from a midstream provider on our Williston Basin production during the year ended December 31, 2016 compared to the year ended December 31, 2015. The increased percentage of ethane was the result of a midstream provider electing to operate its gas processing plant in ethane recovery.

Resale Margin and Storage Activity

QEP purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. The following table is a summary of QEP's financial results from its resale activities:

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	Year Ended December 31,									Change
	2017			2016			2015			2017 vs 2016			2016 vs 2015
	(in millions)
Purchased oil and gas sales	$	62.6		$	101.2		$	620.8		$	(38.6	)	$	(519.6	)
Purchased oil and gas expense	(64.3		)	(105.5		)	(626.8		)	41.2			521.3
Realized gains (losses) on gas storage derivative contracts	—			2.9			3.8			(2.9		)	(0.9		)
Resale margin	$	(1.7	)	$	(1.4	)	$	(2.2	)	$	(0.3	)	$	0.8

Purchased oil and gas sales and expense decreased during the year ended December 31, 2017, compared to the year ended December 31, 2016, due to lower resale volumes, as a result of increased production in areas where the Company has oil and gas transportation commitments.

Purchased oil and gas sales and expense decreased during the year ended December 31, 2016, compared to the year ended December 31, 2015, due to the termination of QEP Marketing agreements on January 1, 2016. As a result of the termination of these agreements QEP is no longer the first purchaser of other working interest owner production. As such, QEP reported lower resale revenue and expenses in the year ended December 31, 2016, compared to 2015.

Operating Expenses

The following table presents QEP's production costs on a unit of production basis:

	Year Ended December 31,						Change
	2017		2016		2015		2017 vs 2016			2016 vs 2015
	(per Boe)
Lease operating expense	$	5.55	$	4.03	$	4.38	$	1.52		$	(0.35	)
Transportation and processing costs	4.61		5.18		5.35		(0.57		)	(0.17		)
Production and property taxes	2.15		1.70		2.16		0.45			(0.46		)
Total production costs	$	12.31	$	10.91	$	11.89	$	1.40		$	(0.98	)

December 31, 2017 compared to December 31, 2016

Lease operating expense (LOE). QEP's LOE increased $70.1 million, or $1.52 per Boe, during the year ended December 31, 2017 compared to 2016. The increase was driven by an increase in workovers in the Williston and Permian basins and Haynesville/Cotton Valley, power and fuel expenses, and services and supplies expenses in the Permian Basin and increased water disposal expenses in Haynesville/Cotton Valley. These increases were partially offset by a decrease in Pinedale due to the Pinedale Divestiture (Refer to Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K for more information).

Transportation and processing costs. QEP's transportation and processing costs decreased $43.9 million, or $0.57 per Boe, during the year ended December 31, 2017 compared to 2016. The decrease in expense during 2017 was primarily attributable to decreases in Pinedale, primarily related to the Pinedale Divestiture and recovery of historical transportation costs, and in Haynesville/Cotton Valley related to the recovery of fees for historical unutilized gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP had a working interest. These decreases were partially offset by increased expenses in Haynesville/Cotton Valley due to increased production and the Williston Basin due to higher transportation rates.

Production and property taxes. In most states in which QEP operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume based. Production and property taxes increased $19.5 million, or $0.45 per Boe, during 2017, primarily a result of increased oil and gas revenues primarily from higher field-level prices partially offset by lower production.

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Depreciation, depletion and amortization (DD&A). DD&A expense decreased $116.6 million during the year ended December 31, 2017, compared to 2016. The decrease in DD&A expense was due to decreases in Pinedale, the Williston Basin and the Uinta Basin, partially offset by increases in Haynesville/Cotton Valley and the Permian Basin. The decrease in Pinedale is primarily the result of a rate decrease due to an impairment recognized in the first quarter of 2016, combined with no DD&A expense in Pinedale during the second half of 2017 as the asset was considered held for sale and sold in September 2017. The decrease in the Williston Basin is the result of decreased production, partially offset by a rate increase from decreased proved reserves. The decrease in the Uinta Basin is the result of decreased production and a rate decrease from increased proved reserves. The increases in Haynesville/Cotton Valley and the Permian Basin were primarily due to increased production.

Exploration expense. Exploration expense increased $20.3 million during the year ended December 31, 2017, compared to 2016, primarily as a result of charging $21.3 million of exploratory well costs related to the Central Basin Platform exploration project to exploration expense. During the third quarter of 2017, based on well performance and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project. Refer to Note 3 – Capitalized Exploratory Well Costs, in Item 8 of Part II of this Annual Report on Form 10-K for more information.

Impairment expense. During the year ended December 31, 2017, QEP recorded impairment charges of $78.9 million, compared to $1,194.3 million of impairment charges recorded during 2016. Of the $78.9 million of impairment charges recorded during 2017, $38.1 million was related to impairment of proved properties due to lower gas prices, $29.0 million was related to expiring leaseholds on unproved properties, an impairment of $6.5 million was related to an underground gas storage facility and $5.3 million related to an impairment of goodwill. Of the $38.1 million impairment of proved properties, $37.1 million related to the Other Northern area and $1.0 million related to Louisiana properties. Of the $1,194.3 million of impairment charges recorded during 2016, $1,172.7 million was related to impairment of proved properties due to lower future oil and gas prices, $17.9 million was related to expiring leaseholds on unproved properties and $3.7 million related to an impairment of goodwill. Of the $1,172.7 million impairment of proved properties, $1,164.0 million related to Pinedale properties, $4.7 million related to Uinta Basin properties, $3.4 million related to Other Northern properties and $0.6 million related to QEP's remaining Other Southern properties.

General and administrative (G&A) expense.During 2017, G&A expense decreased $43.0 million, or 22%, compared to 2016. The decrease in G&A expense in 2017 compared to 2016 was primarily due to a $27.7 million decrease in legal expenses and loss contingencies and a $19.1 million decrease in share-based compensation, primarily due to a decrease in the value of the performance share unit plan. These decreases were partially offset by an increase in labor, benefits and employee expenses.

Net gain (loss) from asset sales. During the year ended December 31, 2017, QEP recognized a gain on sale of assets of $213.5 million, compared to a gain on sale of $5.0 million during the year ended December 31, 2016. The gain on sale of assets recognized in 2017 was primarily related to the Pinedale Divestiture, in which we recorded a pre-tax gain on sale of $180.4 million, and the sale of Other Northern properties. The gain on sale of assets recognized in 2016 was primarily due to the continued divestitures of properties in the Other Southern area.

December 31, 2016 compared to December 31, 2015

Lease operating expense. QEP's LOE decreased $14.1 million, or $0.35 per Boe, during the year ended December 31, 2016, compared to 2015. The decrease was driven by a decrease in the Permian Basin as a result of lower workover and chemical expenses, a decrease in the Other Southern area as a result of continued divestitures of non-core properties and a decrease in the Uinta Basin due to lower maintenance and repair expenses, lower services and supplies expenses and lower workover expenses. These decreases were partially offset by an increase in the Williston Basin due to increased workovers, increased produced water disposal expenses and increased maintenance and repair expenses.

Transportation and processing costs. QEP's transportation and processing costs decreased $2.1 million, or $0.17 per Boe, during the year ended December 31, 2016, compared to 2015. The decrease in expense during 2016 was primarily attributable to additional expenses incurred in Haynesville/Cotton Valley as a result of recognizing additional fees in 2015 related to unutilized gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP has a working interest. This decrease was partially offset by increases in the Permian and Williston basins due to increased production and a rate increase in the Williston Basin.

Production and property taxes. Production and property taxes decreased $22.8 million, or $0.46 per Boe, during the year ended December 31, 2016, compared to 2015, primarily a result of decreased oil and gas revenues primarily from lower field-level prices, as well as production tax refunds.

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Depreciation, depletion and amortization. DD&A expense decreased $10.0 million during the year ended December 31, 2016, compared to 2015. The decrease in DD&A expense was due to decreases in Pinedale and the Williston Basin, partially offset by increases in the Permian Basin, Haynesville/Cotton Valley and the Uinta Basin. The decrease in Pinedale is primarily the result of a rate decrease due to an impairment recognized in the first quarter of 2016, combined with decreased production, while the decrease in the Williston Basin is the result of a rate decrease from increased proved reserves, partially offset by an increase in production. The increases in Haynesville/Cotton Valley and the Uinta Basin were primarily due to increased rates due to a decrease in proved reserves as well as increased production in Haynesville/Cotton Valley, while the increase in the Permian Basin was primarily due to increased production.

Impairment expense. During the year ended December 31, 2016, QEP recorded impairment charges of $1,194.3 million, compared to impairment charges of $55.6 million recorded during 2015. Of the $1,194.3 million of impairment charges recorded during 2016, $1,172.7 million was related to impairment of proved properties due to lower future oil and gas prices, $17.9 million was related to expiring leaseholds on unproved properties and $3.7 million related to an impairment of goodwill. Of the $1,172.7 million impairment on proved properties, $1,164.0 million related to Pinedale properties, $4.7 million related to Uinta Basin properties, $3.4 million related to Other Northern properties and $0.6 million related to Other Southern properties. Of the $55.6 million of impairment charges recorded during 2015, $39.3 million was related to impairment of proved properties due to lower future oil and gas prices, $2.0 million was related to expiring leaseholds on unproved properties and $14.3 million related to impairment of goodwill. Of the $39.3 million impairment on proved properties, $20.2 million related to Other Southern properties, $18.4 million related to Other Northern properties and $0.7 million related to Permian Basin properties.

General and administrative expense. During 2016, G&A expense increased $28.5 million, or 17%, compared to 2015. The increase in G&A expense in 2016 compared to 2015 was primarily due to a $32.7 million increase in legal expenses and loss contingencies and an $8.6 million increase in share-based compensation, primarily due to an increase in the mark-to-market value of the Deferred Compensation Wrap Plan and CIP. These increases were partially offset by a $6.9 million decrease in professional and outside services expenses and a $6.6 million decrease in severance payments and restructuring costs (Refer to Note 7 – Restructuring Costs, in Item 8 of Part II of this Annual Report on Form 10-K for more information).

Net gain (loss) from asset sales. During the year ended December 31, 2016, QEP recognized a gain on sale of assets of $5.0 million, compared to a gain on sale of $4.6 million during the year ended December 31, 2015. The gain on sale of assets recognized in 2016 and 2015 was primarily due to the continued divestitures of non-core properties in the Other Southern area.

Non-Operating Expenses

December 31, 2017 compared to December 31, 2016

Realized and unrealized gains (losses) on derivative contracts. Gains and losses on derivative contracts are comprised of both realized and unrealized gains and losses on QEP's commodity derivative contracts, which are marked-to-market each period. During the year ended December 31, 2017, gains on commodity derivative instruments were $24.5 million, of which $69.9 million were unrealized gains on derivative contracts related to production and storage contracts, $29.9 million were unrealized losses related to the Pinedale Divestiture (Refer to Note 6 – Derivative Contracts, in Item 8 of Part II of this Annual Report on Form 10-K for more information) and $15.5 million were realized losses. During 2016, losses on commodity derivative instruments were $233.0 million, of which $367.0 million were unrealized losses, partially offset by $134.0 million of realized gains.

Interest and other income (expense). Interest and other income (expense) decreased $22.1 million during the year ended December 31, 2017, compared to 2016. The decrease was primarily the result of $22.6 million of bargain purchase gains recognized in 2016 that related to acquisitions which were accounted for as a business combination under ASC 805, Business Combinations during the year ended December 31, 2016 (Refer to Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K for more information).

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Loss from early extinguishment of debt. Loss from early extinguishment of debt increased $32.7 million during the year ended December 31, 2017, compared to 2016. The increase during the year ended December 31, 2017, was primarily the result of the early repayment of senior notes (Refer to Note 8 – Debt, in Item 8 of Part II of this Annual Report on Form 10-K for more information).

Interest expense.Interest expense decreased $5.4 million, or 4%, during the year ended December 31, 2017, compared to 2016. The decrease during the year ended December 31, 2017, was primarily related to the repayment of the 6.05% senior notes in September 2016.

Income tax (provision) benefit. Income tax benefit decreased $396.0 million during the year ended December 31, 2017, compared to 2016. The decrease in income tax benefit was the result of decreased net loss before income taxes partially offset by the federal rate change from 35% to 21% as a result of the federal tax reform and change in state income tax, which resulted in a combined effective federal and state income tax rate of 727.7% during the year ended December 31, 2017, compared to 36.3% for the year ended December 31, 2016.

December 31, 2016 compared to December 31, 2015

Realized and unrealized gains (losses) on derivative contracts. During the year ended December 31, 2016, losses on commodity derivative instruments were $233.0 million, of which $367.0 million were unrealized losses, partially offset by $134.0 million in realized gains. During 2015, gains on commodity derivative instruments were $277.2 million, of which $460.9 million were realized gains, partially offset by $183.7 million in unrealized losses.

Interest and other income (expense). Interest and other income (expense) increased $33.8 million during the year ended December 31, 2016, compared to 2015. The increase was primarily the result of $22.6 million of bargain purchase gains recognized related to acquisitions which were accounted for as a business combination under ASC 805, Business Combinations during the year ended December 31, 2016 (Refer to Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K for more information) and a pension curtailment expense of $11.2 million recognized in the second quarter of 2015 related to a change in the Company's pension plan (Refer to Note 11 – Employee Benefits, in Item 8 of Part II of this Annual Report on Form 10-K for more information).

Interest expense. Interest expense decreased $2.4 million, or 2%, during the year ended December 31, 2016, compared to 2015. The decrease during the year ended December 31, 2016, was primarily related to the $176.8 million repayment of senior notes on September 1, 2016.

Income tax (provision) benefit. Income tax benefit increased $614.6 million during the year ended December 31, 2016, compared to 2015. The increase in income tax benefit was the result of increased net loss before income taxes, partially offset by a lower combined effective federal and state income tax rate of 36.3% during the year ended December 31, 2016, compared to 38.5% for the year ended December 31, 2015. The decrease in the rate was due to a state income tax rate change and a state return to provision adjustment.

LIQUIDITY AND CAPITAL RESOURCES

QEP strives to maintain a sufficient liquidity position to ensure financial flexibility, withstand commodity price volatility and fund its development projects, operations and capital expenditures. The Company utilizes derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company's cash flows. QEP generally funds its operations and planned capital expenditures with cash flow from its operating activities, cash on hand and borrowings under its revolving credit facility. The Company expects that these sources of cash will be sufficient to fund its operations and capital expenditures during the next 12 months and the foreseeable future.

QEP also periodically accesses debt and equity markets and sells properties. In 2018, QEP plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valley and, if successful, use the proceeds to fund on-going operations, reduce debt, repurchase shares and for general corporate purposes. In 2017, the Company issued $500.0 million of senior notes and used the majority of the proceeds to repay $445.7 million of senior notes; paid fees and expenses associated with the repayment and used the remainder for general corporate purposes.

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QEP received aggregate proceeds of approximately $806.8 million related to the Pinedale Divestiture and the sale of properties during the year ended December 31, 2017. All of the proceeds from the Pinedale Divestiture were used to close the 2017 Permian Basin Acquisition. QEP has made offers to various persons who own additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the original purchase. If all offers are accepted, QEP now expects that the aggregate purchase price will not exceed $50.0 million. In February 2018, QEP entered into agreements for an aggregate purchase price of $36.1 million, subject to customary purchase price adjustments. The transactions and any remaining offers, if accepted, are expected to be funded with borrowings under the credit facility and are expected to close in the first quarter of 2018.

In 2016, QEP issued 60.95 million shares of common stock through two public offerings and received net cash proceeds of approximately $781.4 million, which the Company used to fund the 2016 Permian Basin Acquisition and for general corporate purposes. QEP received aggregate cash proceeds of approximately $29.0 million and $21.8 million related to the sale of non-core properties during the years ended December 31, 2016 and 2015, respectively.

The Company estimates, that as of December 31, 2017, it could incur additional indebtedness of approximately $640.0 million and continue to be in compliance with the covenants contained in its revolving credit facility. To the extent actual operating results, realized commodity prices or uses of cash differ from the Company's assumptions, QEP's liquidity could be adversely affected.

Credit Facility

In November 2017, QEP entered into the Seventh Amendment to its Credit Agreement, which, among other things, reduced the aggregate principal amount of commitments to $1.25 billion and extended the maturity date, subject to satisfaction of certain conditions, to September 1, 2022. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The amended credit agreement contains financial covenants (that are defined in the credit agreement) that limit the amount of debt the Company can incur and may limit the amount available to be drawn under the credit facility including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarter ending December 31, 2017, 4.00 times commencing with the fiscal quarter ending March 31, 2018, through the fiscal quarter ending December 31, 2018, and 3.75 times thereafter, and (iii) during a ratings trigger period (as defined), a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2019, must exceed net funded debt by 1.40 times commencing on January 1, 2019, through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. The company is currently not subject to the present value coverage ratio. As of December 31, 2017 and 2016, QEP was in compliance with the covenants under the credit agreement.

During the year ended December 31, 2017, QEP's weighted-average interest rate on borrowings from its credit facility was 3.52%. As of December 31, 2017, QEP had $89.0 million outstanding and $1.0 million in letters of credit outstanding under the credit facility. As of December 31, 2016, QEP had no borrowings outstanding and $2.8 million in letters of credit outstanding under the credit facility. At February 23, 2018, QEP had $154.0 million of borrowings outstanding and had $1.0 million of letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement.

Senior Notes

During the quarter ended December 31, 2017, the Company issued $500.0 million in 5.625% Senior Notes due in 2026. The Company used the proceeds to repay $445.7 million of debt during the year ended December 31, 2017, as follows:

• $134.0 million to redeem its outstanding 6.80% Senior Notes due in 2018;

• $84.3 million of its 6.80% Senior Notes due in 2020 pursuant to a tender offer; and

• $227.4 million of its 6.875% Senior Notes due in 2021 pursuant to a tender offer.

The Company's senior notes outstanding as of December 31, 2017, totaled $2,099.3 million principal amount and are comprised of five issuances as follows:

• $51.7 million 6.80% Senior Notes due March 2020;

• $397.6 million 6.875% Senior Notes due March 2021;

• $500.0 million 5.375% Senior Notes due October 2022;

• $650.0 million 5.25% Senior Notes due May 2023; and

• $500.0 million 5.625% Senior Notes due March 2026.

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Cash Flow from Operating Activities

Cash flows from operating activities are primarily affected by oil, gas and NGL production volumes and commodity prices (including the effects of settlements of the Company's derivative contracts) and by changes in working capital. QEP enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future oil, gas and NGL production for the next 12 to 36 months.

Net cash provided by operating activities is presented below:

	Year Ended December 31,									Change
	2017			2016			2015			2017 vs 2016			2016 vs 2015
	(in millions)
Net income (loss)	$	269.3		(1,245.0		)	$	(149.4	)	$	1,514.3		$	(1,095.6	)
Non-cash adjustments to net income	335.8			1,794.1			1,193.4			(1,458.3		)	600.7
Changes in operating assets and liabilities	(6.7		)	114.6			(562.7		)	(121.3		)	677.3
Net cash provided by operating activities	$	598.4		$	663.7		$	481.3		$	(65.3	)	$	182.4

Net cash provided by operating activities during the year ended December 31, 2017, decreased $65.3 million compared to 2016, which included a $1,514.3 millionincrease in net income, a $1,458.3 milliondecrease in non-cash adjustments to net income and a $121.3 milliondecrease in cash from operating assets and liabilities. During the year ended December 31, 2017, non-cash adjustments to net income primarily included, DD&A expense of $754.5 million, impairment expense of $78.9 million and a $32.7 million loss from early extinguishment of debt, partially offset by deferred income taxes of $314.8 million and a $213.5 million net gain from asset sales. The decrease in changes in operating assets and liabilities of $6.7 million was primarily comprised of a $20.6 million decrease in other that predominantly included decreases in interest payable and asset retirement obligation as well as an increase in accounts receivable of $2.0 million, primarily related to timing of receipts. These decreases were partially offset by a decrease in federal income taxes receivable of $13.7 million and an increase in accounts payable and accrued expenses of $3.5 million.

Net cash provided by operating activities during the year ended December 31, 2016, increased $182.4 million compared to 2015, which included a $1,095.6 millionincrease in net loss, a $600.7 millionincrease in non-cash adjustments to the net loss and a $677.3 millionincrease in cash from operating assets and liabilities. During the year ended December 31, 2016, non-cash adjustments to net loss primarily included impairment expense of $1,194.3 million, DD&A expense of $871.1 million and unrealized losses on derivative contracts of $367.0 million, partially offset by a decrease in deferred income taxes of $651.3 million. The increase in changes in operating assets and liabilities primarily included a decrease in accounts receivable of $95.3 million and a decrease in income taxes receivable of $68.7 million, primarily related to a federal income tax refund received in the third quarter of 2016, partially offset by a decrease in accounts payable and accrued expenses of $50.3 million, primarily related to timing of payments and receipts.

Cash Flow from Investing Activities

A comparison of capital expenditures for the years ended December 31, 2017, 2016 and 2015, are presented in the table below:

	Year Ended December 31,							Change
	2017			2016		2015		2017 vs 2016			2016 vs 2015
Property acquisitions	$	815.2		$	645.2	$	98.3	$	170.0		$	546.9
Property, plant and equipment capital expenditures	1,219.8			530.1		1,011.9		689.7			(481.8		)
Total accrued capital expenditures	2,035.0			1,175.3		1,110.2		859.7			65.1
Change in accruals and other non-cash adjustments	(60.2		)	32.8		129.2		(93.0		)	(96.4		)
Total cash capital expenditures	$	1,974.8		$	1,208.1	$	1,239.4	$	766.7		$	(31.3	)

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During the year ended December 31, 2017, on an accrual basis, the Company invested $1,219.8 million on property, plant and equipment capital expenditures, excluding property acquisitions, an increase of $689.7 million compared to 2016, primarily due to increased capital expenditures in the Permian Basin and Haynesville/Cotton Valley. In 2017, QEP's capital expenditures were $704.3 million in the Permian Basin (including midstream infrastructure of $95.9 million, primarily related to fresh water supply, produced water gathering, salt water disposal, gas and oil gathering and oil terminal facilities), $283.5 million in the Williston Basin, $179.5 million in Haynesville/Cotton Valley, $22.9 million in Pinedale and $3.7 million in the Uinta Basin. In addition, during the year ended December 31, 2017, QEP acquired various oil and gas properties for a total purchase price of $815.2 million, which was primarily related to the 2017 Permian Basin Acquisition and included undeveloped leasehold acreage, producing wells and additional surface acreage in the Permian Basin. These acquisitions were primarily funded with proceeds of approximately $806.8 million from the Pinedale Divestiture and the sale of other assets.

During the year ended December 31, 2016, on an accrual basis, the Company invested $530.1 million on property, plant and equipment expenditures, excluding property acquisitions, a decrease of $481.8 million compared to 2015. In 2016, QEP's capital expenditures were $243.7 million in the Williston Basin, $141.5 million in the Permian Basin, $64.4 million in Haynesville/Cotton Valley, $54.4 million in Pinedale, $10.8 million in the Uinta Basin and $4.7 million in the Other Northern area. In addition, during the year ended December 31, 2016, QEP acquired various oil and gas properties for a total purchase price of $645.2 million, of which $639.0 million was cash and $6.2 million was non-cash related to the settlement of an accounts receivable balance. The $645.2 million of acquisitions was primarily related to the 2016 Permian Basin Acquisition and also included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage in the Permian and Williston basins. These acquisitions were funded with proceeds from the June 2016 equity offering and cash on hand. Partially offsetting the acquisition capital outflow was $29.0 million of proceeds from non-core asset divestitures, primarily in the Other Southern area. In 2015, QEP's capital expenditures were $502.0 million in the Williston Basin, $215.9 million in the Permian Basin, $176.9 million in Pinedale, $68.6 million in the Uinta Basin, $36.9 million in Haynesville/Cotton Valley, $3.7 million in the Other Northern area and $3.4 million in the Other Southern area. In addition, during the year ended December 31, 2015, QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for a total purchase price of $98.3 million, which included an acquisition of additional interests in QEP operated wells and undeveloped acreage. Partially offsetting the acquisition capital outflow was $21.8 million of cash proceeds from non-core asset divestitures, primarily in the Other Southern and Other Northern areas.

The mid-point of our forecasted capital expenditures (excluding property acquisitions) for 2018 is $1,075.0 million. QEP intends to fund capital expenditures (excluding property acquisitions) with cash flow from operating activities, cash on hand and borrowings under the credit facility. The aggregate levels of capital expenditures for 2018 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, oil, gas and NGL prices, industry conditions, acquisitions and divestitures, available liquidity to fund the expenditures and changes in management's business strategies. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP's estimates.

Cash Flow from Financing Activities

During the year ended December 31, 2017, net cash provided by financing activities was $125.8 million compared to net cash provided by financing activities of $583.1 million during the year ended December 31, 2016. During the year ended December 31, 2017, the Company issued 5.625% Senior Notes due 2026 receiving gross cash proceeds of $500.0 million, and repaid $445.7 million of Senior Notes comprised of the redemption of the 6.80% Senior Notes due 2018 and settling the tender offers of the 6.80% Senior Notes due 2020 and 6.875% Senior Notes due 2021. In addition, during the year ended December 31, 2017, QEP had borrowings from the credit facility of $492.0 million and repayments on its credit facility of $403.0 million. As of December 31, 2017, long-term debt consisted of $2,160.8 million total debt, of which $2,099.3 million is senior notes, $89.0 million outstanding on the credit facility, and $27.5 million of net original issue discount and unamortized debt issuance costs.

During the year ended December 31, 2016, net cash provided by financing activities was $583.1 million compared to net cash used in financing activities of $47.7 million during the year ended December 31, 2015. During the year ended December 31, 2016, the Company received net proceeds from the March and June 2016 equity offerings of $781.4 million, repaid the 6.05% Senior Notes of $176.8 million and had a decrease in checks outstanding in excess of cash balances of $17.5 million. As of December 31, 2016, long-term debt consisted of $2,045.0 million in senior notes (excluding $24.1 million of net original issue discount and unamortized debt issuance costs). As of December 31, 2016, long-term debt consisted of $2,020.9 million total debt, of which $2,045.0 million is senior notes and $24.1 million of net original issue discount and unamortized debt issuance costs.

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Off-Balance Sheet Arrangements

QEP may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. At December 31, 2017, the Company's material off-balance sheet arrangements included operating leases; drilling, gathering, processing, firm transportation and storage contracts; and undrawn letters of credit. There are no other off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on QEP's financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. See "Contractual Cash Obligations and Other Commitments" below for more information regarding QEP's off-balance sheet arrangements.

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, QEP enters into a variety of contractual cash obligations and other commitments. The following table summarizes the significant contractual cash obligations as of December 31, 2017:

	Payments Due by Year(1)
	Total		2018		2019		2020		2021		2022		After 2022
	(in millions)
Long-term debt	$	2,099.3	$	—	$	—	$	51.7	$	397.6	$	500.0	$	1,150.0
Interest on fixed-rate, long-term debt(2)	633.3		119.9		119.9		117.0		93.7		82.4		100.4
Drilling contracts	5.6		5.6		—		—		—		—		—
Gathering, processing, firm transportation, storage and other	394.0		90.0		68.4		54.9		29.9		28.3		122.5
Asset retirement obligations(3)	214.1		7.5		6.1		6.8		4.2		6.4		183.1
Operating leases	41.0		7.0		7.2		7.4		7.4		7.2		4.8
Total	$	3,387.3	$	230.0	$	201.6	$	237.8	$	532.8	$	624.3	$	1,560.8

___________________________

⁽¹⁾   This table excludes the Company's benefit plan liabilities as future payment dates are unknown. Refer to Note 11 – Employee Benefits, in Item 8 of Part II of this Annual Report on Form 10-K for additional information.

⁽²⁾   Excludes variable rate debt interest payments and commitment fees related to the Company's revolving credit facility.

⁽³⁾   These future obligations are discounted estimates of future expenditures based on expected settlement dates. Refer to Note 4 – Asset Retirement Obligations, in Item 8 of Part II in this Annual Report on Form 10-K for additional information.

Impact of Inflation/Deflation and Pricing

All of QEP's transactions are denominated in U.S. dollars. Typically, as prices for oil and gas increase, associated costs rise. Conversely, as prices for oil and gas decrease, costs decline. Cost declines tend to lag and may not adjust downward in proportion to declining commodity prices. Historically, field-level prices received for QEP's oil and gas production have been volatile. During each of the years ended December 31, 2017 and 2016, commodity prices increased from the previous year, while during the year ended December 31, 2015, commodity prices decreased from the previous year. Changes in commodity prices impact QEP's revenues, estimates of reserves, assessments of any impairment of oil and gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect QEP's ability to raise capital, borrow money, and retain personnel.

Critical Accounting Estimates

QEP's significant accounting policies are described in Note 1 – Summary of Significant Accounting Policies, in Item 8 of Part II of this Annual Report on Form 10-K. The Company's Consolidated Financial Statements are prepared in accordance with GAAP. The preparation of consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. The following is a discussion of the accounting policies, estimates and judgments that management believes are most significant in the application of GAAP used in the preparation of the Company's financial statements.

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Oil, gas and NGL Reserves

One of the most significant estimates the Company makes is the estimate of oil, gas and NGL reserves. Oil, gas and NGL reserve estimates require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, production history, projected future production, economic assumptions relating to commodity prices, operating expenses, severance and other taxes, capital expenditures and remediation costs. The subjective judgments and variances in data for various fields make these estimates less precise than other estimates included in the financial statement disclosures.

Estimates of proved oil, gas and NGL reserves significantly affect the Company's DD&A expense. For example, if estimates of proved reserves decline, the Company's DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also cause QEP to perform an impairment analysis to determine if the carrying amount of oil and gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings. See "Impairment of Long-Lived Assets" below.

QEP engages independent reservoir engineering consultants to prepare estimates of the proved oil, gas and NGL reserves. Reserve estimates are based on a complex and highly interpretive process that is subject to continuous revision as additional production and development drilling information becomes available. Refer to Note 14 – Supplemental Oil and Gas Information (unaudited), in Item 8 of Part II of this Annual Report on Form 10-K.

Successful Efforts Accounting for Oil and Gas Operations

The Company follows the successful efforts method of accounting for oil and gas property acquisitions, exploration, development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production DD&A rate would be significantly affected. Capitalized costs of unproved properties are reclassified to proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.

Capitalized Exploratory Well Costs

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

Impairment of Long-Lived Assets

Proved oil and gas properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value. Triggering events could include, but are not limited to, a reduction of oil, gas and NGL reserves caused by mechanical problems, faster-than-expected decline of production, lease ownership issues and declines in oil, gas and NGL prices. If impairment is indicated, fair value is estimated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices, operating costs and estimates of proved, probable and possible reserves. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors. During the years ended December 31, 2017, 2016 and 2015, QEP recorded impairment expense of $38.1 million, $1,172.7 million and $39.3 million, respectively, related to some of its higher cost, proved properties in both of its Northern and Southern regions, due to lower forward prices.

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Unproved properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term. During the years ended December 31, 2017, 2016 and 2015, QEP recorded impairment charges of $29.0 million, $17.9 million and $2.0 million respectively, related to its unproved properties. The 2017 unproved property impairment charges primarily resulted from unproved leasehold acreage in the Central Basin Platform. Refer to Note 3 – Capitalized Exploratory Well Costs, in Item 8 of Part II of this Annual Report on Form 10-K for additional information. The 2016 and 2015 unproved property impairment charges primarily resulted from lower forward prices and expiring leaseholds.

Asset Retirement Obligations

QEP records asset retirement obligations (ARO) associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. ARO is subject to revisions because of the intrinsic uncertainties present when estimating asset retirement costs and asset retirement settlement dates. Revisions to the ARO estimate can result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. QEP's ARO liability at December 31, 2017 and 2016 was $214.1 million and $231.6 million, respectively.

Accounting for ARO represents a critical accounting estimate because (i) QEP will not incur most of these costs for a number of years, requiring QEP to make estimates over a long period, (ii) laws and regulations could change in the future and/or circumstances affecting QEP's operations could change, either of which could result in significant changes to its current plans, (iii) the methods used or required to plug and abandon non-producing oil and gas wellbores, remove platforms, tanks, production equipment and flow lines, and restore the well site could change, (iv) calculating the fair value of QEP's ARO requires management to estimate projected cash flows, make long-term assumptions about inflation rates, determine its credit-adjusted risk-free interest rates and determine market risk premiums that are appropriate for its operations, and (v) changes in any or all of these estimates could have an impact on QEP's results of operations.

Revenue Recognition

QEP recognizes revenue from oil and gas producing activities in the period that services are provided or products are delivered. Revenues associated with the sale of oil, gas and NGL are accounted for using the sales method, whereby revenue is recognized as oil, gas and NGL are sold to purchasers. Revenues include estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators. An imbalance liability is recorded to the extent that QEP has sold volumes in excess of its share of remaining reserves in an underlying property.

QEP also purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. QEP recognizes revenue from these resale activities when title transfers to the customer.

Litigation and Other Contingencies

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of potential loss for potential accrual in its Consolidated Financial Statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages can be reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.

Legal proceedings are inherently unpredictable, and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoing discovery and/or development of information important to the matter. Refer to Note 9 – Commitments and Contingencies, in Item 8 of Part II of this Annual Report on Form 10-K for additional information regarding litigation and other contingencies.

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Environmental Obligations

Management makes judgments and estimates in accordance with applicable accounting rules when it establishes reserves for environmental remediation, litigation and other contingent matters. Provisions for such matters are expensed when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. Estimates of environmental liabilities are based on a variety of factors, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies and presently enacted laws and regulations. In future periods, a number of factors could significantly change the Company's estimate of environmental remediation costs, such as changes in laws and regulations, changes in the interpretation or administration of laws and regulations, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment and technology. Consequently, it is not possible for management to reliably estimate the amount and timing of all future expenditures related to environmental matters and actual costs may vary significantly. Refer to Note 9 – Commitments and Contingencies, in Item 8 of Part II of this Annual Report on Form 10-K for additional information regarding current environmental claims.

Derivative Contracts

The Company uses commodity derivative instruments, typically fixed-price swaps and costless collars, to reduce the impact of potential downward movements in commodity prices. Accounting rules for derivatives require marking these instruments to fair value at the balance sheet reporting date. The Company follows mark-to-market accounting and recognizes all gains and losses on such instruments in earnings in the period in which they occur. As a result, changes in the fair value of QEP's commodity derivative instruments could have a significant impact on net income. QEP does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. Refer to Note 6 – Derivative Contracts, in Item 8 of Part II of this Annual Report on Form 10-K for additional information.

Pension and Other Postretirement Benefits

QEP maintains closed, defined-benefit pension and other postretirement benefit plans, including both a qualified and a supplemental plan. QEP also provides certain health care and life insurance benefits for certain retired QEP employees. Determination of the benefit obligations for QEP's defined-benefit pension and other postretirement benefit plans impacts the recorded amounts for such obligations on the Consolidated Balance Sheets and the amount of benefit expense recorded on the Consolidated Statements of Operations.

QEP measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement benefit plans include the discount rate, the expected rate of return on plan assets (for funded pension plans) and the rate of future compensation increases. Other assumptions involve demographic factors such as retirement, mortality and turnover. QEP evaluates and updates its actuarial assumptions at least annually. QEP recognizes a pension curtailment immediately when there is a significant reduction in, or an elimination of, defined-benefit accruals for present employees' future services. Refer to Note 11 – Employee Benefits, in Item 8 of Part II of this Annual Report on Form 10-K for additional information.

Share-Based Compensation

QEP issues stock options, restricted share awards and restricted share units to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. The grant date fair value for restricted share awards is determined based on the closing bid price of the Company's common stock on the grant date. Share-based compensation cost for restricted share units is equal to its fair value as of the end of the period and is classified as a liability. QEP uses an accelerated method in recognizing share-based compensation costs for stock options and restricted share awards with graded-vesting periods. Stock options held by employees generally vest in three equal, annual installments and primarily have a term of seven years. Restricted share awards and restricted share units vest in equal installments over a specified number of years after the grant date with the majority vesting in three years. Non-vested restricted share awards have voting and dividend rights; however, sale or transfer is restricted. Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified unfunded deferred compensation plan at the time of vesting. The Company also awards performance share units under its Cash Incentive Plan (CIP) that are generally paid out in cash depending upon the Company's total shareholder return compared to a group of its peers over a three-year period. Share-based compensation cost for the performance share units is equal to its fair value as of the end of the period and is classified as a liability. Refer to Note 10 – Share-Based Compensation, in Item 8 of Part II of this Annual Report on Form 10-K for additional information.

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Income Taxes

The amount of income taxes recorded by QEP requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. QEP has recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. QEP routinely assesses the realizability of its deferred tax assets and reduces such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. QEP routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. The accruals for deferred tax assets and liabilities, including deferred state income tax assets and liabilities, are subject to significant judgment by management and are reviewed and adjusted routinely based on changes in facts and circumstances. Although management considers its tax accruals adequate, material changes in these accruals may occur in the future, based on the impact of tax audits, changes in legislation and resolution of pending or future tax matters. While we are still evaluating the full impact of the new tax legislation, we expect the substantial reduction of the federal corporate tax rate, from 35% to 21%, to benefit our financial results and cash flows in future periods. Refer to Note 12 – Income Taxes, in Item 8 of Part II of this Annual Report on Form 10-K for additional information.

Purchase Price Allocations

QEP periodically acquires assets and assumes liabilities in transactions accounted for as business combinations, such as the 2016 Permian Basin Acquisition. In connection with a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a bargain purchase gain or goodwill. The amount of goodwill or bargain purchase gain recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed and fluctuations in commodity prices.

In estimating the fair values of assets acquired and liabilities assumed in a business combination, QEP makes various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and gas properties. If sufficient market data is not available regarding the fair values of proved and unproved properties, QEP must prepare estimates. To estimate the fair values of these properties, QEP utilizes a discounted cash flow model which utilizes the following inputs to estimate future net cash flows: estimated quantities of oil, gas and NGL reserves; estimates of future commodity prices; and estimated production rates, future operating and development costs, which are based on the Company's historic experience with similar properties. The future net cash flows are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, when a discounted cash flow model is used, the discounted future net cash flows of probable and possible reserves are reduced by additional risk factors. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage.

Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded. Refer to Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K for additional information regarding purchase price allocations.

Recent Accounting Developments

See Recent Accounting Developments in Note 1 – Summary of Significant Accounting Policies, in Item 8 of Part II of this Annual Report on Form 10-K.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP's primary market risks arise from changes in the market price for oil, gas and NGL and volatility in interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. Commodity prices have historically been volatile and are subject to wide fluctuations in response to relatively minor changes in supply and demand. If commodity prices fluctuate significantly, revenues and cash flow may significantly decrease or increase. QEP has long-term contracts for pipeline capacity and is obligated to pay for transportation services with no guarantee that it will be able to fully utilize the contractual capacity of these transportation commitments. In addition, additional non-cash impairment expense of the Company's oil and gas properties may be required if future oil and gas commodity prices experience a significant decline. Furthermore, the Company's revolving credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. To partially manage the Company's exposure to these risks, QEP enters into commodity derivative contracts in the form of fixed-price and basis swaps and collars to manage commodity price risk and periodically enters into interest rate swaps to manage interest rate risk.

Commodity Price Risk Management

QEP uses commodity derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, these arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price and basis swaps and collars. The volume of commodity derivative instruments utilized by the Company may vary from year to year based on QEP's forecasted production. The Company's current derivative instruments do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of December 31, 2017, QEP held commodity price derivative contracts totaling 24.8 million barrels of oil, 147.8 million MMBtu of gas and 0.6 million MMBtu of net gas storage. As of December 31, 2016, QEP held commodity price derivative contracts totaling 20.8 million barrels of oil, 200.9 million MMBtu of gas and 4.0 million MMBtu of net gas storage.

The following table presents QEP's volumes and average prices for its derivative positions as of February 23, 2018. Refer to Note 6 – Derivative Contracts, in Item 8 of Part II of this Annual Report on Form 10-K for open derivative positions as of December 31, 2017.

Production Commodity Derivative Swaps
Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2018	NYMEX WTI	15.4	$	52.48
2019	NYMEX WTI	9.1	$	52.45
Gas sales		(MMBtu)	($/MMBtu)
2018 (Full Year)	NYMEX HH	91.8	$	2.99
2018 (July through December)	NYMEX HH	1.8	$	3.01
2019	NYMEX HH	43.8	$	2.86

Production Commodity Derivative Basis Swaps
Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2018 (Full Year)	NYMEX WTI	Argus WTI Midland	6.7	$	(1.06	)
2018 (July through December)	NYMEX WTI	Argus WTI Midland	0.9	$	(0.71	)
2019	NYMEX WTI	Argus WTI Midland	4.7	$	(0.77	)
Gas sales			(MMBtu)	($/MMBtu)
2018	NYMEX HH	IFNPCR	6.1	$	(0.16	)

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Changes in the fair value of derivative contracts from December 31, 2016 to December 31, 2017, are presented below:

	Commodity derivative contracts
	(in millions)
Net fair value of oil and gas derivative contracts outstanding at December 31, 2016	$	(201.8	)
Contracts settled	15.5
Change in oil and gas prices on futures markets	150.5
Contracts added	(96.1		)
Net fair value of oil and gas derivative contracts outstanding at December 31, 2017	$	(131.9	)

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

	December 31, 2017
	(in millions)
Net fair value – asset (liability)	$	(131.9	)
Fair value if market prices of oil, gas and basis differentials decline by 10%	$	(118.6	)
Fair value if market prices of oil, gas and basis differentials increase by 10%	$	(145.0	)

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $13.1 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $13.3 million as of December 31, 2017. However, a gain or loss eventually would be substantially offset by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding the Company's commodity derivative transactions, refer to Note 6 – Derivative Contracts, in Item 8 of Part II of this Annual Report on Form 10-K.

Interest Rate Risk Management

The Company's ability to borrow and the rates offered by lenders can be adversely affected by illiquid credit markets and the Company's credit rating, as described in the Risk Factors, in Item 1A of Part I of this Annual Report on Form 10-K. The Company's revolving credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. As of December 31, 2017, QEP had $89.0 million outstanding under the credit facility. As of December 31, 2016, QEP had no borrowings outstanding under the credit facility. If interest rates were to increase or decrease 10% during the year ended December 31, 2017, at our average level of borrowing for those same periods, the Company's interest expense would increase or decrease by $0.1 million for the year ended December 31, 2017, or less than 1% of total interest expense.

The remaining $2,099.3 million of the Company's debt is senior notes with fixed interest rates; therefore, it is not affected by interest rate movements. For additional information regarding the Company's debt instruments, refer to Note 8 – Debt, in Item 8 of Part II of this Annual Report on Form 10-K.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial Statements:	Page No.
Report of Independent Registered Public Accounting Firm as of and for the years ended December 31, 2017, 2016 and 2015	78
Consolidated Statements of Operations for the three years ended December 31, 2017	80
Consolidated Statements of Comprehensive Income (Loss) for the three years ended December 31, 2017	81
Consolidated Balance Sheets as of December 31, 2017 and 2016	82
Consolidated Statements of Equity for the three years ended December 31, 2017	83
Consolidated Statements of Cash Flows for the three years ended December 31, 2017	84
Notes Accompanying the Consolidated Financial Statements	85

All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of QEP Resources, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of QEP Resources, Inc. and its subsidiaries as of December 31, 2017 and 2016,and the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for each of the three years in the period ended December 31, 2017, including the related notes (collectively referred to as the "consolidated financial statements").We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework(2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework(2013)issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Assessment of Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company's consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidatedfinancial statements included performing procedures to assess the risks of material misstatement of the consolidatedfinancial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidatedfinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidatedfinancial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

February 28, 2018

We have served as the Company's auditor since 2012.

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QEP RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2017			2016			2015
REVENUES	(in millions, except per share amounts)
Oil sales	$	939.4		$	769.1		$	834.2
Gas sales	494.0			417.1			468.5
NGL sales	111.9			83.5			80.0
Other revenues	15.0			6.2			15.1
Purchased oil and gas sales	62.6			101.2			620.8
Total Revenues	1,622.9			1,377.1			2,018.6
OPERATING EXPENSES
Purchased oil and gas expense	64.3			105.5			626.8
Lease operating expense	294.8			224.7			238.8
Transportation and processing costs	245.3			289.2			291.3
Gathering and other expense	7.3			5.0			5.8
General and administrative	153.5			196.5			168.0
Production and property taxes	114.3			94.8			117.6
Depreciation, depletion and amortization	754.5			871.1			881.1
Exploration expenses	22.0			1.7			2.7
Impairment	78.9			1,194.3			55.6
Total Operating Expenses	1,734.9			2,982.8			2,387.7
Net gain (loss) from asset sales	213.5			5.0			4.6
OPERATING INCOME (LOSS)	101.5			(1,600.7		)	(364.5		)
Realized and unrealized gains (losses) on derivative contracts (Note 6)	24.5			(233.0		)	277.2
Interest and other income (expense)	1.6			23.7			(10.1		)
Loss from early extinguishment of debt	(32.7		)	—			—
Interest expense	(137.8		)	(143.2		)	(145.6		)
INCOME (LOSS) BEFORE INCOME TAXES	(42.9		)	(1,953.2		)	(243.0		)
Income tax (provision) benefit	312.2			708.2			93.6
NET INCOME (LOSS)	$	269.3		$	(1,245.0	)	$	(149.4	)
Earnings (loss) per common share
Basic	$	1.12		$	(5.62	)	$	(0.85	)
Diluted	$	1.12		$	(5.62	)	$	(0.85	)
Weighted-average common shares outstanding
Used in basic calculation	240.6			221.7			176.6
Used in diluted calculation	240.6			221.7			176.6
Dividends per common share	$	—		$	—		$	0.08

Refer to Notes accompanying the Consolidated Financial Statements.

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QEP RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,
	2017			2016			2015
	(in millions)
Net income (loss)	$	269.3		$	(1,245.0	)	$	(149.4	)
Other comprehensive income, net of tax:
Future tax effective rate change(1)	(3.8		)	—			—
Pension and other postretirement plans adjustments:
Current period prior service cost(2)	2.4			—			(0.6		)
Current period net actuarial (gain) loss(3)	5.8			(5.6		)	(0.5		)
Amortization of prior service cost(4)	0.5			0.8			8.2
Amortization of net actuarial (gain) loss(5)	0.3			0.5			0.3
Net curtailment and settlement cost incurred(6)	0.4			—			4.5
Other comprehensive income (loss)	5.6			(4.3		)	11.9
Comprehensive income (loss)	$	274.9		$	(1,249.3	)	$	(137.5	)

____________________________

⁽¹⁾  The new tax legislation changed the federal corporate income tax rate from 35% to 21% starting in 2018. The rate change caused the Company to revalue its deferred tax liabilities and assets using the lower rate.

⁽²⁾  Presented net of income tax expense of $0.8 million for the year ended December 31, 2017 and net of income tax benefit of $0.3 million for the year ended December 31, 2015.

⁽³⁾  Presented net of income tax expense of $1.8 million for the year ended December 31, 2017 and net of income tax benefit of $3.3 million and $0.3 million for the years ended December 31, 2016 and 2015, respectively.

⁽⁴⁾  Presented net of income tax expense of $0.2 million, $0.5 million, and $4.9 million for the years ended December 31, 2017, 2016, and 2015, respectively.

⁽⁵⁾  Presented net of income tax expense of $0.1 million, $0.3 million, and $0.2 million for the years ended December 31, 2017, 2016, and 2015, respectively.

⁽⁶⁾  Presented net of income tax expense of $0.1 million and $2.6 million for the years ended December 31, 2017 and 2015, respectively.

Refer to Notes accompanying the Consolidated Financial Statements.

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QEP RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

	December 31, 2017			December 31, 2016
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	—		$	443.8
Accounts receivable, net	142.1			155.7
Income tax receivable	4.9			18.6
Fair value of derivative contracts	3.4			—
Hydrocarbon inventories, at lower of average cost or net realizable value	3.6			10.4
Prepaid expenses	10.7			11.4
Other current assets	0.7			0.2
Total Current Assets	165.4			640.1
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	12,470.9			14,232.5
Unproved properties	1,095.8			871.5
Gathering and other	319.7			301.8
Materials and supplies	37.8			32.7
Total Property, Plant and Equipment	13,924.2			15,438.5
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,642.9			8,797.7
Gathering and other	124.3			101.8
Total Accumulated Depreciation, Depletion and Amortization	6,767.2			8,899.5
Net Property, Plant and Equipment	7,157.0			6,539.0
Fair value of derivative contracts	0.1			—
Other noncurrent assets	72.3			66.3
TOTAL ASSETS	$	7,394.8		$	7,245.4
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	44.0		$	12.3
Accounts payable and accrued expenses	372.1			269.7
Production and property taxes	31.6			30.1
Interest payable	26.0			32.9
Fair value of derivative contracts	103.6			169.8
Total Current Liabilities	577.3			514.8
Long-term debt	2,160.8			2,020.9
Deferred income taxes	518.0			825.9
Asset retirement obligations	206.6			225.8
Fair value of derivative contracts	31.8			32.0
Other long-term liabilities	102.4			123.3
Commitments and Contingencies (Note 9)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 243.0 million and 240.7 million shares issued, respectively	2.4			2.4
Treasury stock - 2.0 million and 1.1 million shares, respectively	(34.2		)	(22.9		)
Additional paid-in capital	1,398.2			1,366.6
Retained earnings	2,442.6			2,173.3
Accumulated other comprehensive income (loss)	(11.1		)	(16.7		)
Total Common Shareholders' Equity	3,797.9			3,502.7
TOTAL LIABILITIES AND EQUITY	$	7,394.8		$	7,245.4

Refer to Notes accompanying the Consolidated Financial Statements.

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QEP RESOURCES, INC.

CONSOLIDATED STATEMENTS OF EQUITY

	Common Stock			Treasury Stock					Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income(Loss)			Total
	Shares	Amount		Shares		Amount
	(in millions)
Balance at December 31, 2014	176.2	$	1.8	(0.8	)	$	(25.4	)	$	535.3	$	3,587.9		$	(24.3	)	$	4,075.3
Net income (loss)	—	—		—		—			—		(149.4		)	—			(149.4		)
Dividends paid	—	—		—		—			—		(14.1		)	—			(14.1		)
Share-based compensation	1.1	—		0.3		10.8			19.5		(6.1		)	—			24.2
Change in pension and postretirement liability, net of tax	—	—		—		—			—		—			11.9			11.9
Balance at December 31, 2015	177.3	1.8		(0.5	)	(14.6		)	554.8		3,418.3			(12.4		)	3,947.9
Net income (loss)	—	—		—		—			—		(1,245.0		)	—			(1,245.0		)
Equity issuance, net of offering costs	61.0	0.6		—		—			780.8		—			—			781.4
Share-based compensation	2.4	—		(0.6	)	(8.3		)	31.0		—			—			22.7
Change in pension and postretirement liability, net of tax	—	—		—		—			—		—			(4.3		)	(4.3		)
Balance at December 31, 2016	240.7	2.4		(1.1	)	(22.9		)	1,366.6		2,173.3			(16.7		)	3,502.7
Net income (loss)	—	—		—		—			—		269.3			—			269.3
Share-based compensation	2.3	—		(0.9	)	(11.3		)	31.6		—			—			20.3
Change in pension and postretirement liability, net of tax	—	—		—		—			—		—			5.6			5.6
Balance at December 31, 2017	243.0	$	2.4	(2.0	)	$	(34.2	)	$	1,398.2	$	2,442.6		$	(11.1	)	$	3,797.9

Refer to Notes accompanying the Consolidated Financial Statements.

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QEP RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2017			2016			2015
OPERATING ACTIVITIES	(in millions)
Net income (loss)	$	269.3		$	(1,245.0	)	$	(149.4	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	754.5			871.1			881.1
Deferred income taxes	(314.8		)	(651.3		)	25.3
Impairment	78.9			1,194.3			55.6
Dry hole exploratory well expense	21.3			—			—
Share-based compensation	22.4			35.6			34.7
Pension curtailment loss	—			—			11.2
Amortization of debt issuance costs and discounts	6.2			6.4			6.2
Bargain purchase gain from acquisitions	0.4			(22.6		)	—
Net (gain) loss from asset sales	(213.5		)	(5.0		)	(4.6		)
Loss from early extinguishment of debt	32.7			—			—
Unrealized (gains) losses on marketable securities	(2.9		)	(1.4		)	0.2
Unrealized (gains) losses on derivative contracts	(40.0		)	367.0			183.7
Other non-cash activity	(9.4		)	—			—
Changes in operating assets and liabilities
Accounts receivable	(2.0		)	95.3			124.6
Hydrocarbon inventories	(1.1		)	8.7			15.5
Prepaid expenses	(0.2		)	18.5			16.7
Accounts payable and accrued expenses	3.5			(50.3		)	(34.5		)
Federal income taxes receivable	13.7			68.7			(619.4		)
Other	(20.6		)	(26.3		)	(65.6		)
Net Cash Provided by (Used in) Operating Activities	598.4			663.7			481.3
INVESTING ACTIVITIES
Property acquisitions	(815.2		)	(639.0		)	(98.3		)
Property, plant and equipment, including exploratory well expense	(1,159.6		)	(569.1		)	(1,141.1		)
Proceeds from disposition of assets	806.8			29.0			21.8
Net Cash Provided by (Used in) Investing Activities	(1,168.0		)	(1,179.1		)	(1,217.6		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	31.7			(17.5		)	(24.9		)
Long-term debt issued	500.0			—			—
Long-term debt issuance costs paid	(14.4		)	—			(2.6		)
Long-term debt extinguishment costs paid	(28.1		)	—			—
Long-term debt repaid	(445.6		)	(176.8		)	—
Proceeds from credit facility	492.0			—			—
Repayments of credit facility	(403.0		)	—			—
Treasury stock repurchases	(6.8		)	(4.1		)	(2.7		)
Other capital contributions	—			—			(0.2		)
Dividends paid	—			—			(14.1		)
Proceeds from issuance of common stock, net	—			781.4			—
Excess tax (provision) benefit on share-based compensation	—			0.1			(3.2		)
Net Cash Provided by (Used in) Financing Activities	125.8			583.1			(47.7		)
Change in cash and cash equivalents	(443.8		)	67.7			(784.0		)
Beginning cash and cash equivalents	443.8			376.1			1,160.1
Ending cash and cash equivalents	$	—		$	443.8		$	376.1

Refer to Notes accompanying the Consolidated Financial Statements.

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QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Significant Accounting Policies

Nature of Business

QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Northern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".

Principles of Consolidation

The Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Consolidated Financial Statements were prepared in accordance with GAAP and with the instructions for annual reports on Form 10-K and Regulations S-X. All significant intercompany accounts and transactions have been eliminated in consolidation.

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

Termination of Marketing Agreements

Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and Haynesville Gathering. As a result, QEP Energy directly markets its own oil, gas and NGL production. While QEP continues to act as an agent for the sale of oil, gas and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had prior to 2016.

In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP had one reportable segment effective January 1, 2016. The Company has recast its financial statements for historical periods to reflect the impact of the termination of marketing agreements to show its financial results without segments.

Reclassifications

Certain prior period amounts on the Consolidated Statements of Operations, Consolidated Balance Sheets and Consolidated Statements of Cash Flows have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's net income (loss), earnings (loss) per share, cash flows, current assets or retained earnings previously reported.

Use of Estimates

The preparation of the Consolidated Financial Statements and Notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management's estimates and assumptions is the estimate of proved oil, gas and NGL reserves, which are used in the calculation of depreciation, depletion and amortization rates of its oil and gas properties, impairment of proved properties and asset retirement obligations. Changes in estimated quantities of its reserves could impact the Company's reported financial results as well as disclosures regarding the quantities and value of proved oil and gas reserves. Other items subject to estimates and assumptions include the carrying amount of property, plant and equipment, assigning fair value and allocating purchase price in connection with business combinations, valuation allowances for receivables, income taxes, valuation of derivatives instruments, accrued liabilities, accrued revenue and related receivables and obligations related to employee benefits, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.

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Risks and Uncertainties

The Company's revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil, gas and NGL, which are affected by many factors outside of QEP's control, including changes in market supply and demand. Changes in market supply and demand are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. Field-level prices received for QEP's oil and gas production have historically been volatile and may be subject to significant fluctuations in the future. The Company's derivative contracts serve to mitigate in part the effect of this price volatility on the Company's cash flows, and the Company has derivative contracts in place for a portion of its expected future oil and gas production. Refer to Note 6 – Derivative Contracts for the Company's open oil and gas commodity derivative contracts.

Revenue Recognition

QEP recognizes revenue from oil and gas producing activities in the period that services are provided or products are delivered. Revenues associated with the sale of oil, gas and NGL are accounted for using the sales method, whereby revenue is recognized when these commodities are sold to purchasers. Revenues include estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators. An imbalance liability is recorded to the extent that QEP has sold volumes in excess of its share of remaining reserves in an underlying property.

QEP also purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. QEP recognizes revenue from these resale activities when title transfers to the customer.

Cash and Cash Equivalents and Restricted Cash

Cash equivalents consist principally of highly liquid investments in securities with original maturities of three months or less made through commercial bank accounts that result in available funds the next business day.

As of December 31, 2017, QEP had no unrestricted cash and restricted cash of $23.4 million. As of December 31, 2016, QEP had unrestricted cash of $443.8 million and restricted cash of $21.6 million. QEP's restricted cash is primarily cash deposited into an escrow account related to a title dispute between third parties in the Williston Basin and is included in "Other noncurrent assets" on the Consolidated Balance Sheets.

Supplemental cash flow information is shown in the table below:

	Year Ended December 31,
	2017			2016			2015
Supplemental Disclosures	(in millions)
Cash paid for interest, net of capitalized interest	$	134.9		$	139.1		$	139.4
Cash paid (refund received) for income taxes, net	$	(0.3	)	$	(123.5	)	$	487.8
Non-cash investing activities
Change in capital expenditure accrual balance	$	60.2		$	(32.8	)	$	(129.2	)

Accounts Receivable

Accounts receivable consists mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company's oil and gas receivables are collected and bad debts are minimal. However, if commodity prices remain low for an extended period of time, the Company could incur increased levels of bad debt expense. Recovery of bad debt associated with accounts receivable for the year ended December 31, 2017 was $1.0 million. Bad debt expense associated with accounts receivable for the years ended December 31, 2016 and 2015, was $1.8 million, and $0.5 million, respectively. Bad debt recovery or expense is included in "General and administrative" expense on the Consolidated Statements of Operations. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. The allowance for bad debt expenses was $1.6 million at December 31, 2017, and $4.8 million at December 31, 2016.

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Property, Plant and Equipment

Property, plant and equipment balances are stated at historical cost. Material and supplies inventories are valued at the lower of cost or net realizable value. Maintenance and repair costs are expensed as incurred. Significant accounting policies for our property, plant and equipment are as follows:

Successful Efforts Accounting for Oil and Gas Operations

The Company follows the successful efforts method of accounting for oil and gas property acquisitions, exploration, development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected. Capitalized costs of unproved properties are reclassified to proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.

Capitalized Exploratory Well Costs

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

Depreciation, Depletion and Amortization (DD&A)

Capitalized proved leasehold costs are depleted on a field-by-field basis using the unit-of-production method and the estimated proved oil and gas reserves. Capitalized costs of exploratory wells that have found proved oil and gas reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves for a successful effort field. The Company capitalizes an estimate of the fair value of future abandonment costs.

DD&A for the Company's remaining properties is generally based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets using the straight-line method. The estimated useful lives of those assets depreciated under the straight-line basis generally range as follows:

Buildings	10 to 30 years
Leasehold improvements	3 to 10 years
Service, transportation and field service equipment	3 to 7 years
Furniture and office equipment	3 to 7 years

Impairment of Long-Lived Assets

Proved oil and gas properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value. Triggering events could include, but are not limited to, a reduction of oil, gas and NGL reserves caused by mechanical problems, faster-than-expected decline of production, lease ownership issues, and declines in oil, gas and NGL prices. If impairment is indicated, fair value is estimated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices, operating costs and estimates of proved, probable and possible reserves. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors.

Unproved properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.

87

During the year ended December 31, 2017, QEP recorded impairment charges of $78.9 million, of which $38.1 million was related to proved properties due to lower future gas prices, $29.0 million was primarily related to unproved leasehold acreage in the Central Basin Platform (Refer to Note 3 – Capitalized Exploratory Well Costs for additional information), $6.5 million was related to impairment of an underground gas storage facility and $5.3 million was related to the impairment of goodwill. Of the $38.1 million impairment of proved properties, $37.1 million related to the Other Northern area and $1.0 million related to Louisiana properties.

During the year ended December 31, 2016, QEP recorded impairment charges of $1,194.3 million, of which $1,172.7 million was related to proved properties due to lower future oil and gas prices, $17.9 million was related to expiring leaseholds on unproved properties and $3.7 million was related to the impairment of goodwill. Of the $1,172.7 million impairment of proved properties, $1,164.0 million related to Pinedale properties, $4.7 million related to Uinta Basin properties, $3.4 million related to the Other Northern area and $0.6 million related to QEP's remaining Other Southern properties.

During the year ended December 31, 2015, QEP recorded impairment charges of $55.6 million, of which $39.3 million was related to proved properties due to lower future oil and gas prices, $2.0 million was related to expiring leaseholds on unproved properties and $14.3 million was related to the impairment of goodwill. Of the $39.3 million impairment on proved properties, $20.2 million related to QEP's remaining Other Southern properties, $18.4 million related Other Northern properties, and $0.7 million related to Permian Basin properties.

Asset Retirement Obligations

QEP is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. ARO associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement costs, is depreciated over the useful life of the asset. ARO are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded to both the ARO liability and the long-lived asset. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. Refer to Note 4 – Asset Retirement Obligations for additional information.

Goodwill

Goodwill represents the excess of the amount paid over the fair value of assets acquired in a business combination and is not subject to amortization. During the year ended December 31, 2017, QEP early adopted ASU 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment. Under the new guidance QEP performs an annual goodwill impairment test by comparing the fair value of a reporting unit with its carry amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. QEP determines the fair value of its reporting units in which goodwill is allocated using the income approach in which the fair value is estimated based on the value of expected future cash flows. Key assumptions used in the cash flow model include estimated quantities of oil, gas and NGL reserves, including both proved reserves and risk-adjusted unproved reserves, and including probable and possible reserves; estimates of market prices considering forward commodity price curves as of the measurement date; estimates of revenue and operating costs over a multi-year period; and estimates of capital costs.

During the year ended December 31, 2017, QEP recorded $5.3 million of goodwill, which related to an acquisition in the first quarter of 2017. During the fourth quarter of 2017, QEP performed an annual impairment test over goodwill as described above, which resulted in a full write down of goodwill of $5.3 million.

During the years ended December 31, 2016 and 2015, QEP recorded $3.7 million and $14.3 million, respectively, of goodwill. Annual impairment tests over goodwill at year end December 31, 2016 and 2015 resulted in a full write down of $3.7 million and $14.3 million, respectively.

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Litigation and Other Contingencies

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Consolidated Financial Statements. The amount of ultimate loss may differ from these estimates. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Refer to Note 9 – Commitments and Contingencies for additional information.

QEP accrues material losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.

Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. QEP uses commodity derivative instruments, typically fixed-price swaps and costless collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. QEP does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. Additionally, QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates.

These derivative contracts are recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Consolidated Statements of Operations in the month of settlement and are also marked-to-market monthly. Refer to Note 6 – Derivative Contracts for additional information.

Credit Risk

Management believes that its credit review procedures, loss reserves, cash deposits and investments, and collection procedures have adequately provided for usual and customary credit-related losses. Exposure to credit risk may be affected by extended periods of low commodity prices, as well as the concentration of customers in certain regions due to changes in economic or other conditions. Customers include commercial and industrial enterprises and financial institutions that may react differently to changing conditions.

The Company utilizes various processes to monitor and evaluate its credit risk exposure, which include closely monitoring current market conditions and counterparty credit fundamentals, including public credit ratings, where available. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals, and is aggregated across all lines of business, including derivatives, physical exposure and short-term cash investments. To further manage the level of credit risk, the Company requests credit support and, in some cases, requests parental guarantees, letters of credit or prepayment from companies with perceived higher credit risk. Loss reserves are periodically reviewed for adequacy and may be established on a specific case basis. The Company also has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

The Company enters into International Swap Dealers Association Master Agreements (ISDA Agreements) with each of its derivative counterparties prior to executing derivative contracts. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or counterparty to a derivative contract. The Company routinely monitors and manages its exposure to counterparty risk related to derivative contracts by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties public credit ratings, and avoiding concentration of credit exposure by transacting with multiple counterparties. The Company's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings.

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The Company's five largest customers accounted for 59%, 48%, and 30% of QEP's revenues for the years ended December 31, 2017, 2016 and 2015, respectively. During the year ended December 31, 2017, Shell Trading Company, Occidental Energy Marketing, Andeavor Logistics LP, BP Energy Company and Plains Marketing LP accounted for 14%, 13%, 13%, 10% and 10%, respectively, of QEP's total revenues. During the year ended December 31, 2016, Shell Trading Company, BP Energy Company and Valero Marketing & Supply Company accounted for 14%, 10% and 10%, respectively, of QEP's total revenues. During the year ended December 31, 2015, no customer accounted for 10% or more of QEP's total revenues. 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.

Income Taxes

The amount of income taxes recorded by QEP requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. QEP has recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. Deferred income taxes are provided for the temporary differences arising between the book and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods.

ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company's recorded income tax benefits will be fully realized, except as noted below. As of December 31, 2017, the Company had a valuation allowance of $56.8 million against the state net operating loss deferred tax asset because management does not forecast future income in Oklahoma and Louisiana to offset net operating losses before they expire. All federal income tax returns prior to 2017 have been examined by the Internal Revenue Service and are closed. Income tax returns for 2017 have not yet been filed. Most state tax returns for 2014 and subsequent years remain subject to examination.

The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more-likely-than-not to be sustained upon examination by the relevant taxing authorities. Our policy is to recognize any interest earned on income tax refunds in "Interest and other income (expense)" on the Consolidated Statements of Operations, any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statements of Operations and to recognize any penalties related to uncertain tax positions in "General and administrative" expense on the Consolidated Statements of Operations. As of December 31, 2017 and 2016, QEP had $19.0 million and $15.6 million of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which was included within "Other long-term liabilities" on the Consolidated Balance Sheets. During the year ended December 31, 2017, the Company incurred $0.7 million of estimated interest expense related to uncertain tax positions. During the year ended December 31, 2016, the Company incurred $0.7 million of estimated interest expense and $0.6 million of estimated penalties related to uncertain tax positions. During the year ended December 31, 2015, the Company incurred $0.5 million of estimated interest expense and $2.2 million of estimated penalties related to uncertain tax positions.

On December 22, 2017 the Tax Cuts and Jobs Act (H.R.1) (Tax Legislation) was signed into law, which resulted in significant changes to U.S. federal income tax law. QEP expects that these changes will positively impact QEP's future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate of 21% compared to 35%. The Tax Legislation also repeals the corporate alternative minimum tax (AMT). Several provisions of the new tax law such as limitations on the deductibility of interest expense and certain executive compensation and the inability to use Section 1031 like-kind exchanges for assets such as machinery and equipment could apply to QEP; however, we do not believe that they will materially impact QEP's financial statements. The impact of the Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made and actions the Company may take as a result of the Tax Legislation.  Additionally, guidance issued by the relevant regulatory authorities regarding the Tax Legislation may materially impact QEP's financial statements. The Company will continue to analyze the Tax Legislation to determine the full impact of the new law, on the Company's consolidated financial statements and operations.

Treasury Stock

We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders' equity in the Consolidated Balance Sheets. QEP acquires treasury stock from stock forfeitures and withholdings and uses the acquired treasury stock for stock option exercises and certain stock grants to employees; refer to Note 10 – Share-Based Compensation for additional information.

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Earnings (Loss) Per Share

Basic earnings (loss) per share (EPS) are computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP's unvested restricted share awards are included in weighted-average basic common shares outstanding because, once the shares are granted, the restricted share awards are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted share awards are eligible to receive dividends.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings (loss) per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) per common share. For the years ended December 31, 2017 and 2015, there were no anti-dilutive shares. For the year ended December 31, 2016, there were 0.1 million shares not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss from continuing operations.

The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation:

	December 31,
	2017	2016	2015
	(in millions)
Weighted-average basic common shares outstanding	240.6	221.7	176.6
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—
Average diluted common shares outstanding	240.6	221.7	176.6

Share-Based Compensation

QEP issues stock options, restricted share awards and restricted share units to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. The grant date fair value for restricted share awards is determined based on the closing bid price of the Company's common stock on the grant date. Share-based compensation cost for restricted share units is equal to its fair value as of the end of the period and is classified as a liability. QEP uses an accelerated method in recognizing share-based compensation costs for stock options and restricted share awards with graded-vesting periods. Stock options held by employees generally vest in three equal, annual installments and primarily have a term of seven years. Restricted share awards and restricted share units vest in equal installments over a specified number of years after the grant date with the majority vesting in three years. Non-vested restricted share awards have voting and dividend rights; however, sale or transfer is restricted. Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified unfunded deferred compensation plan at the time of vesting. The Company also awards performance share units under its CIP that are generally paid out in cash depending upon the Company's total shareholder return compared to a group of its peers over a three-year period. Share-based compensation cost for the performance share units is equal to its fair value as of the end of the period and is classified as a liability. For additional information, refer to Note 10 – Share-Based Compensation for additional information.

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Pension and Other Postretirement Benefits

QEP maintains closed, defined-benefit pension and other postretirement benefit plans, including both a qualified and a supplemental plan. QEP also provides certain health care and life insurance benefits for certain retired QEP employees. Determination of the benefit obligations for QEP's defined-benefit pension and other postretirement benefit plans impacts the recorded amounts for such obligations on the Consolidated Balance Sheets and the amount of benefit expense recorded to the Consolidated Statements of Operations.

QEP measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement benefit plans include the discount rate, the expected rate of return on plan assets (for funded pension plans) and the rate of future compensation increases. Other assumptions involve demographic factors such as retirement, mortality and turnover. QEP evaluates and updates its actuarial assumptions at least annually. QEP recognizes a pension curtailment immediately when there is a significant reduction in, or an elimination of, defined-benefit accruals for present employees' future services. Refer to Note 11 – Employee Benefits for additional information.

Comprehensive Income (Loss)

Comprehensive income (loss) is the sum of net income (loss) as reported in the Consolidated Statements of Operations and changes in the components of other comprehensive income. Other comprehensive income (loss) includes certain items that are recorded directly to equity and classified as accumulated other comprehensive income (AOCI), which includes changes in the underfunded portion of the Company's defined-benefit pension and other postretirement benefits plans and changes in deferred income taxes on such amounts. These transactions do not represent the culmination of the earnings process but result from periodically adjusting historical balances to fair value.

Recent Accounting Developments

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In addition, new and enhanced disclosures will be required. The amendment is effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 15, 2016. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The Company does not expect net income (loss) or cash flows to be materially impacted by the new standard; however, the Company expects that a portion of its transportation and processing costs will be netted within revenue under the new standard. In addition, the Company will have expanded disclosure requirements, as a result of the adoption of the ASU. The Company has selected the modified retrospective method and will adopt this guidance on the effective date of January 1, 2018.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-06, Derivatives and hedging (Topic 815): Contingent put and call options in debt instruments, which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The amendment was effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption was permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.

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In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment was effective prospectively for reporting periods beginning after December 15, 2016, and early adoption was permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of certain cash receipts and cash payments , which intends to reduce the diversity in practice in how certain transactions are classified in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the fourth quarter of 2017 and the adoption of this standard did not have a material impact on the Company's Consolidated Financial Statements.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the definition of a business, which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of businesses. The amendment will be effective prospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the fourth quarter of 2017 and the adoption of this standard did not have a material impact on the Company's Consolidated Financial Statements; however, this standard may impact the determination of whether future acquisitions are accounted for as a business combination or an asset acquisition.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment, which eliminates the requirement to calculate implied fair value of goodwill to measure the goodwill impairment charge. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, which changes how employers of a defined benefit plan present net periodic benefit cost in the statements of operations. The amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and recast the years ended December 31, 2016 and 2015. The adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements. Refer to Note 11 – Employee Benefits for additional information regarding the Company's pension and other postretirement plans.

Note 2 – Acquisitions and Divestitures

2017 Permian Basin Acquisition

In the fourth quarter of 2017, QEP acquired additional oil and gas properties in the Permian Basin for an aggregate purchase price of $720.7 million, subject to post-closing purchase price adjustments (the 2017 Permian Basin Acquisition). The 2017 Permian Basin Acquisition consists of approximately 15,100 acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. QEP structured the transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded the purchase price with the proceeds from the Pinedale Divestiture. In accordance with the early adoption of ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the definition of a business in the fourth quarter of 2017, the 2017 Permian Basin Acquisition meets the definition of an asset acquisition because substantially all of the total fair value acquired relates to undeveloped leaseholds which do not have outputs. In addition, QEP has made offers to various persons who own additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the original purchase. If all offers are accepted, the aggregate purchase price is not expected to exceed $50.0 million.

2016 Permian Basin Acquisition

In October 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $591.0 million (the 2016 Permian Basin Acquisition). The 2016 Permian Basin Acquisition consists of approximately 9,600 net acres in Martin County, Texas, which are primarily held by production from existing vertical wells. The 2016 Permian Basin Acquisition was funded with cash on hand, which included proceeds from an equity offering in June 2016.

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The 2016 Permian Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included significant proved properties. QEP allocated the cost of the 2016 Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $80.2 million and a net income of $221.4 million were generated from the acquired properties for the year ended December 31, 2017. Revenues of $3.8 million and a net loss of $0.7 million were generated from the acquired properties from October 19, 2016 to December 31, 2016. The revenue and net income (loss) are included in QEP's Consolidated Statements of Operations. During the year ended December 31, 2016, QEP incurred acquisition-related costs of $2.3 million, which are included in "General and administrative" expense on the Consolidated Statements of Operations. In conjunction with the 2016 Permian Basin Acquisition, the Company recorded a $17.8 million bargain purchase gain. The acquisition resulted in a bargain purchase gain primarily as a result of an increase in future oil prices from the execution of the purchase and sale agreement to the closing date of the acquisition. The bargain purchase gain is reported on the Consolidated Statements of Operations within "Interest and other income (expense)".

The following table presents a summary of the Company's purchase accounting entries (in millions) as of December 31, 2017:

Consideration:
Total consideration	$	591.0
Amounts recognized for fair value of assets acquired and liabilities assumed:
Proved properties	$	406.2
Unproved properties	214.2
Asset retirement obligations	(11.6		)
Bargain purchase gain	(17.8		)
Total fair value	$	591.0

The following unaudited, pro forma results of operations are provided for the year ended December 31, 2016. Pro forma results are not provided for the year ended December 31, 2017, because the 2016 Permian Basin Acquisition occurred during the fourth quarter of 2016; and therefore, the results are included in QEP's results of operations for the year ended December 31, 2017. The supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the periods presented, or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the year ended December 31, 2016, the acquired properties' historical results of operations and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting, and quantifying, the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the 2016 Permian Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.

	Year ended December 31,
	2016
	Actual			Pro forma
	(in millions, except per share amounts)
Revenues	$	1,377.1		$	1,392.5
Net income (loss)	$	(1,245.0	)	$	(1,246.8	)
Earnings (loss) per common share
Basic	$	(5.62	)	$	(5.62	)
Diluted	$	(5.62	)	$	(5.62	)

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Other Acquisitions

In addition to the 2017 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2017, which primarily included undeveloped leasehold acreage, producing wells and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million, subject to customary post-closing purchase price adjustments. In conjunction with the acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired.

In addition to the 2016 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2016, primarily in the Permian and Williston basins, for an aggregate purchase price of $54.6 million, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage. In conjunction with the acquisitions, the Company recorded $3.7 million of goodwill, which was subsequently impaired, and a $4.4 million bargain purchase gain. The bargain purchase gain is reported on the Consolidated Statements of Operations within "Interest and other income (expense)".

During the year ended December 31, 2015, QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for a total purchase price of $98.3 million, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage. In conjunction with the acquisitions, the Company recorded $14.3 million of goodwill, which was subsequently impaired.

Pinedale Divestiture

In September 2017, QEP sold its Pinedale assets (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to post-closing purchase price adjustments, and recorded a pre-tax gain on sale of $180.4 million which was recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations. As part of the purchase and sale agreement, at the request of the buyer, QEP agreed to enter into derivative contracts covering a portion of Pinedale's future production. Those derivative contracts were novated to the buyer at closing. In addition, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. The fair value of the deficiency charges was measured utilizing an internally developed cash flow model discounted at QEP's weighted average cost of debt. Given the unobservable nature of the inputs, the fair value calculation associated with the deficiency charges is considered Level 3 within the fair value hierarchy. As of December 31, 2017, the liability associated with estimated future payments for this commitment was $30.6 million, of which $27.4 million is reported on the Consolidated Balance Sheets within "Accounts payable and accrued expenses" and $3.2 million is reported on the Consolidated Balance Sheets within "Other long-term liabilities".

QEP accounted for revenues and expenses related to Pinedale, including the pre-tax gain on sale of $180.4 million, during the years ended December 31, 2017, 2016 and 2015, as income on the Consolidated Statements of Operations because the sale of the Pinedale assets did not cause a strategic shift for the Company and as a result, did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The Pinedale Divestiture did, however, represent the sale of an individually significant component. For the year ended December 31, 2017, QEP recorded net income before income taxes related to Pinedale, prior to the divestiture, of $251.0 million, which includes the pre-tax gain on sale of $180.4 million. For the year ended December 31, 2016, QEP recorded a net loss before income taxes of $1,152.7 million. The net loss before income taxes was primarily due to an impairment on proved properties of $1,164.0 million recognized in 2016 as a result of a decrease in expected future gas prices. For the year ended December 31, 2015, QEP recorded net loss before income taxes of $45.6 million related to Pinedale.

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Other Divestitures

In addition to the Pinedale Divestiture, during the year ended December 31, 2017, QEP also sold its Central Basin Platform assets (Central Basin Platform Divestiture) and received net cash proceeds of $3.5 million. Refer to Note 3 – Capitalized Exploratory Well Costs for more information. In addition, QEP received net cash proceeds of $85.1 million and recorded a pre-tax gain on sale of $33.1 million, primarily related to the sale of properties in the Other Northern area.

During the year ended December 31, 2016, QEP sold its interest in certain non-core properties, primarily in the Other Southern area for aggregate proceeds of $29.0 million and recorded a pre-tax gain on sale of $8.6 million.

During the year ended December 31, 2015, QEP sold its interest in certain non-core properties in the Other Southern area for aggregate proceeds of $31.7 million, of which $21.8 million was cash and $9.9 million of accounts receivable and recorded a pre-tax gain on sale of $21.0 million. During the year ended December 31, 2016, QEP recorded a pre-tax loss of sale of $0.9 million, due to post-closing purchase price adjustments from the sale of such properties.

These gains and losses are reported on the Consolidated Statements of Operations within "Net gain (loss) from asset sales".

Note 3 – Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs are presented in the table below.

	Capitalized Exploratory Well Costs
	2017			2016			2015
	(in millions)
Balance at January 1,	$	14.2		$	2.6		$	12.6
Additions to capitalized exploratory well costs	10.7			11.7			6.0
Reclassifications to proved properties	(3.6		)	—			(16.0		)
Capitalized exploratory well costs charged to expense	(21.3		)	(0.1		)	—
Balance at December 31,	$	—		$	14.2		$	2.6

The balance at December 31, 2016 and 2015 represents the amount of capitalized exploratory well costs that are pending the determination of proved reserves.

During the years ended December 31, 2017 and 2016, QEP's exploratory well activity was related to the Central Basin Platform exploration project in the Permian Basin targeting the Woodford Formation. QEP completed a second exploratory well related to this project in the first half of 2017. During the year ended December 31, 2017, based on the performance of the two exploratory wells that were drilled and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project and would seek to monetize the assets. QEP charged $21.3 million of exploratory well costs to exploration expense. In conjunction with the expensing of the exploratory well costs, QEP charged $28.3 million of the associated unproved leasehold acreage in the Central Basin Platform to impairment expense during the year ended December 31, 2017. QEP wrote down the Central Basin Platform assets to their fair market value of $3.6 million and reclassified the assets to proved properties. During the fourth quarter of 2017, QEP closed on the Central Basin Platform Divestiture for net cash proceeds of $3.5 million.

Note 4 – Asset Retirement Obligations

QEP records ARO associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $214.1 million and $231.6 million ARO liability as of December 31, 2017 and 2016, respectively, $7.5 million and $5.8 million, respectively, was included as a liability in "Accounts payable and accrued expenses" on the Consolidated Balance Sheets.

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The following is a reconciliation of the changes in the Company's ARO for the periods specified below:

	Asset Retirement Obligations
	2017			2016
	(in millions)
ARO liability at January 1,	$	231.6		$	206.8
Accretion	7.7			8.9
Additions(1)	23.5			17.0
Revisions	8.5			6.5
Liabilities related to assets sold(2)	(34.9		)	—
Liabilities settled	(22.3		)	(7.6		)
ARO liability at December 31,	$	214.1		$	231.6

___________________________

⁽¹⁾  Additions for the year ended December 31, 2017, include $14.2 million related to the 2017 Permian Basin Acquisition and additions for the year ended December 31, 2016, include $11.6 million related to the 2016 Permian Basin Acquisition (refer to Note 2 – Acquisitions and Divestitures for more information).

⁽²⁾  Liabilities related to assets sold for the year ended December 31, 2017, include $34.9 million related to the Pinedale Divestiture (refer to Note 2 – Acquisitions and Divestitures for more information).

Note 5 – Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 also establishes a fair value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.

QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (refer to Note 6 – Derivative Contracts for additional information) is based on market prices posted on the respective commodity exchange on the last trading day of the reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels at the end of the reporting period.

Certain of the Company's commodity derivative instruments are valued using industry standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also incorporates nonperformance risk for counterparties and for QEP. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with the counterparty exists.

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The fair value of financial assets and liabilities at December 31, 2017 and 2016, is shown in the table below:

	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
	December 31, 2017
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	20.6	$	—	$	(17.2	)	$	3.4
Fair value of derivative contracts – long-term	—		2.3		—		(2.2		)	0.1
Total financial assets	$	—	$	22.9	$	—	$	(19.4	)	$	3.5
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	120.8	$	—	$	(17.2	)	$	103.6
Fair value of derivative contracts – long-term	—		34.0		—		(2.2		)	31.8
Total financial liabilities	$	—	$	154.8	$	—	$	(19.4	)	$	135.4
	December 31, 2016
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	—	$	—	$	—		$	—
Fair value of derivative contracts – long-term	—		—		—		—			—
Total financial assets	$	—	$	—	$	—	$	—		$	—
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	169.8	$	—	$	—		$	169.8
Fair value of derivative contracts – long-term	—		32.0		—		—			32.0
Total financial liabilities	$	—	$	201.8	$	—	$	—		$	201.8

____________________________

⁽¹⁾  The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Consolidated Balance Sheets for the contracts that contain netting provisions. Refer to Note 6 – Derivative Contracts for additional information regarding the Company's derivative contracts.

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K:

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	December 31, 2017				December 31, 2016
Financial Assets	(in millions)
Cash and cash equivalents	$	—	$	—	$	443.8	$	443.8
Financial Liabilities
Checks outstanding in excess of cash balances	$	44.0	$	44.0	$	12.3	$	12.3
Long-term debt	$	2,160.8	$	2,256.2	$	2,020.9	$	2,104.3

98

The carrying amounts of cash and cash equivalents and checks outstanding in excess of cash balances approximate fair value. The fair value of fixed-rate long-term debt is based on the trading levels and dollar prices for the Company's debt at the end of the year. The carrying amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt was set for periods of one month.

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO include plugging costs and reserve lives. A reconciliation of the Company's ARO is presented in Note 4 – Asset Retirement Obligations.

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a nonrecurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. During the years ended December 31, 2017 and 2016, the Company recorded impairments of certain proved oil and gas properties of $38.1 million and $1,172.7 million, respectively, resulting in a reduction of the associated carrying value to fair value. The fair value of the property was measured utilizing the income approach and utilizing inputs which are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. Given the unobservable nature of the inputs, fair value calculations associated with proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. Refer to Note 1 – Summary of Significant Accounting Policies for additional information on impairment of oil and gas properties.

Acquisitions of proved and unproved properties are also measured at fair value on a nonrecurring basis. The Company utilizes a discounted cash flow model to estimate the fair value of acquired property as of the acquisition date which utilizes the following inputs to estimate future net cash flows: (i) estimated quantities of oil, gas and NGL reserves; (ii) estimates of future commodity prices; and (iii) estimated production rates, future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the acquired properties is considered Level 3 within the fair value hierarchy. Refer to Note 2 – Acquisitions and Divestitures for additional information on the fair value of acquired properties.

Note 6 – Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production, but generally, QEP enters into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. In addition, QEP may enter into commodity derivative contracts on a portion of its storage transactions. QEP does not enter into commodity derivative contracts for speculative purposes.

QEP uses commodity derivative instruments known as fixed-price swaps or costless collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma or oil price swaps that use ICE Brent oil prices as the reference price. Gas price derivative instruments are typically structured as fixed-price swaps or costless collars at NYMEX Henry Hub or regional price indices. QEP also enters into oil and gas basis swaps to achieve a fixed-price swap for a portion of its oil and gas sales at prices that reference specific regional index prices.

99

QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. QEP's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties public credit ratings and avoiding the concentration of credit exposure by transacting with multiple counterparties. The Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

Derivative Contracts – Production

The following table presents QEP's volumes and average prices for its commodity derivative swap contracts as of December 31, 2017:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2018	NYMEX WTI	16.8	$	52.48
2019	NYMEX WTI	8.0	$	51.78
Gas sales		(MMBtu)	($/MMBtu)
2018 (Full Year)	NYMEX HH	109.5	$	2.99
2018 (July through December)	NYMEX HH	1.8	$	3.01
2019	NYMEX HH	36.5	$	2.88

QEP uses oil and gas basis swaps, combined with NYMEX WTI and NYMEX HH fixed price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table presents details of QEP's oil and gas basis swaps as of December 31, 2017:

Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2018 (Full Year)	NYMEX WTI	Argus WTI Midland	7.3	$	(1.06	)
2018 (July through December)	NYMEX WTI	Argus WTI Midland	0.9	$	(0.71	)
2019	NYMEX WTI	Argus WTI Midland	4.0	$	(0.80	)
Gas sales			(MMBtu)	($/MMBtu)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)

Derivative Contracts – Gas Storage

QEP enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage. The following table presents QEP's volumes and average prices for its gas storage commodity derivative swap contracts as of December 31, 2017:

Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2018	SWAP	IFNPCR	0.6	$	3.06

100

QEP Derivative Financial Statement Presentation

The following table identifies the Consolidated Balance Sheets location of QEP's outstanding derivative contracts on a gross contract basis as opposed to the net contract basis presentation on the Consolidated Balance Sheets and the related fair values at the balance sheet dates:

		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
		December 31,
	Balance Sheet line item	2017		2016		2017		2016
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	20.6	$	—	$	120.8	$	169.8
Long-term:
Commodity	Fair value of derivative contracts	2.3		—		34.0		32.0
Total derivative instruments		$	22.9	$	—	$	154.8	$	201.8

101

The effects of the change in fair value and settlement of QEP's derivative contracts recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Consolidated Statements of Operations are summarized in the following table:

Derivative contracts not designated as cash flow hedges	Year Ended December 31,
	2017			2016			2015
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	6.8		$	86.3		$	353.7
Gas derivative contracts	(22.3		)	44.8			103.4
Gas Storage
Gas derivative contracts	—			2.9			3.8
Realized gains (losses) on commodity derivative contracts	(15.5		)	134.0			460.9
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(66.2		)	(217.2		)	(244.9		)
Gas derivative contracts	133.6			(145.4		)	62.0
Gas Storage
Gas derivative contracts	2.5			(4.4		)	(0.8		)
Unrealized gains (losses) on commodity derivative contracts	69.9			(367.0		)	(183.7		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts	$	54.4		$	(233.0	)	$	277.2
Derivatives associated with the Pinedale Divestiture(1)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	(1.3	)	$	—		$	—
Gas derivative contracts	(23.5		)	—			—
NGL derivative contracts	(5.1		)	—			—
Unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture	$	(29.9	)	$	—		$	—
Total realized and unrealized gains (losses) on commodity derivative contracts	$	24.5		$	(233.0	)	$	277.2

_______________________

⁽¹⁾  The unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 2 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations.

Note 7 – Restructuring Costs

In April 2016, the Company streamlined its organizational structure, resulting in a reduction of approximately 6% of its total workforce. The total costs related to the 2016 restructuring were approximately $1.9 million and were related to one-time termination benefits. During the year ended December 31, 2016, restructuring costs of $1.9 million were incurred and paid related to the 2016 restructuring. The Company did not incur additional costs related to the 2016 restructuring in 2017.

102

During 2015, QEP had multiple restructuring events, including the closure of its Tulsa office, which occurred in the third quarter of 2015. The total costs related to the 2015 restructuring events were approximately $8.3 million, of which approximately $5.3 million was related to one-time termination benefits and approximately $3.0 million was related to relocation of certain employees. During the year ended December 31, 2016, restructuring costs of $0.6 million were incurred and paid related to the Tulsa office closure, all of which were related to the relocation of certain employees. The Company did not incur additional costs related to the closure of its Tulsa office.

All restructuring costs were recorded within "General and administrative" expense on the Consolidated Statements of Operations.

Note 8 – Debt

As of the indicated dates, the principal amount of QEP's debt consisted of the following:

	December 31,
	2017			2016
	(in millions)
Revolving Credit Facility due 2022	$	89.0		$	—
6.80% Senior Notes due 2018(1)	—			134.0
6.80% Senior Notes due 2020(1)	51.7			136.0
6.875% Senior Notes due 2021(1)	397.6			625.0
5.375% Senior Notes due 2022	500.0			500.0
5.25% Senior Notes due 2023	650.0			650.0
5.625% Senior Notes due 2026(1)	500.0			—
Less: unamortized discount and unamortized debt issuance costs	(27.5		)	(24.1		)
Total long-term debt outstanding	$	2,160.8		$	2,020.9

_______________________

⁽¹⁾  During the quarter ended December 31, 2017, the Company issued $500.0 million of 5.625% Senior Notes due in 2026. The Company used the majority of the proceeds from the offering to redeem all of its outstanding 6.80% Senior Notes due in 2018 and fund tender offers for $84.3 million of 6.80% Senior Notes due in 2020 and $227.4 million of its outstanding 6.875% Senior Notes due in 2021. The Company recorded a $32.7 million loss from early extinguishment of debt related to the redemption and tender offers.

Of the total debt outstanding on December 31, 2017, the 6.80% Senior Notes due March 1, 2020, the 6.875% Senior Notes due March 1, 2021 and the 5.375% Senior Notes due October 1, 2022, will mature within the next five years. In addition, the revolving credit facility matures on September 1, 2022.

Credit Facility

In November 2017, QEP entered into the Seventh Amendment to its Credit Agreement, which, among other things, reduced the aggregate principal amount of commitments to $1.25 billion and extended the maturity date, subject to satisfaction of certain conditions, to September 1, 2022. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The amended credit agreement contains financial covenants (that are defined in the credit agreement) that limit the amount of debt the Company can incur and may limit the amount available to be drawn under the credit facility including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarter ending December 31, 2017, 4.00 times commencing with the fiscal quarter ending March 31, 2018, through the fiscal quarter ending December 31, 2018, and 3.75 times thereafter, and (iii) during a ratings trigger period (as defined), a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2019, must exceed net funded debt by 1.40 times commencing on January 1, 2019, through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. The company is currently not subject to the present value coverage ratio. As of December 31, 2017 and 2016, QEP was in compliance with the covenants under the credit agreement.

103

During the year ended December 31, 2017, QEP's weighted-average interest rates on borrowings from its credit facility were 3.52%. As of December 31, 2017, QEP had $89.0 million of borrowings outstanding and $1.0 million in letters of credit outstanding under the credit facility. As of December 31, 2016, QEP had no borrowings outstanding and $2.8 million in letters of credit outstanding under the credit facility.

Senior Notes

At December 31, 2017, the Company had $2,099.3 million principal amount of senior notes outstanding with maturities ranging from March 2020 to March 2026 and coupons ranging from 5.25% to 6.875%. The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP's senior notes contain customary events of default and covenants that may limit QEP's ability to, among other things, place liens on its property or assets.

Note 9 – Commitments and Contingencies

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Consolidated Financial Statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.

Legal proceedings are inherently unpredictable and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires judgment about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoing discovery and/or development of information important to the matter.

Litigation

Landowner Litigation – In October, 2017, the owners of certain surface and mineral interests in Martin and Andrews County, Texas filed suit against QEP, alleging QEP improperly used the surface of the properties and failed to correctly pay royalties, and are seeking money damages and a declaratory judgment that portions of the oil and gas leases covering the properties are no longer in effect. The Company continues to evaluate the allegations and its defenses. The Company is unable to make an estimate of the reasonably possible loss at this early stage.

Commitments

QEP has contracted for gathering, processing, firm transportation and storage services with various third parties. Market conditions, drilling activity and competition may prevent full utilization of the contractual capacity. In addition, QEP has contracts with third parties who provide drilling services. Annual payments and the corresponding years for gathering, processing, transportation, storage, drilling, and fractionation contracts are as follows (in millions):

Year	Amount
2018	$	95.6
2019	$	68.4
2020	$	54.9
2021	$	29.9
2022	$	28.3
After 2022	$	122.5

104

QEP rents office space throughout its scope of operations from third-party lessors. Rental expense from operating leases amounted to $9.6 million, $9.1 million, and $8.0 million during the years ended December 31, 2017, 2016 and 2015, respectively. Minimum future payments under the terms of long-term operating leases for the Company's primary office locations are as follows (in millions):

Year	Amount
2018	$	7.0
2019	$	7.2
2020	$	7.4
2021	$	7.4
2022	$	7.2
After 2022	$	4.8

Note 10 – Share-Based Compensation

QEP issues stock options, restricted share awards and restricted share units under its LTSIP and awards performance share units under its CIP to certain officers, employees, and non-employee directors. QEP recognizes expense over the vesting periods for the stock options, restricted share awards, restricted share units and performance share units. There were 5.0 million shares available for future grants under the LTSIP at December 31, 2017.

Share-based compensation expense related to continuing operations is recognized within "General and administrative" expense on the Consolidated Statements of Operations and is summarized in the table below.

	Year Ended December 31,
	2017			2016		2015
	(in millions)
Stock options	$	2.3		$	2.3	$	2.9
Restricted share awards	24.6			23.7		25.6
Performance share units	(4.5		)	9.4		6.2
Restricted share units	—			0.2		—
Total share-based compensation expense	$	22.4		$	35.6	$	34.7

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of grant. Fair value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for calculating the value of options not traded on an exchange. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares. The Company expenses forfeitures of stock options as they occur.

105

The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:

	Stock Option Assumptions
	Year Ended December 31,
	2017			2016			2015
Weighted-average grant date fair value of awards granted during the period	$	6.44		$	3.77		$	6.82
Risk-free interest rate range	1.66% - 1.81%			0.99% - 1.15%			1.38% - 1.38%
Weighted-average risk-free interest rate	1.8		%	1.2		%	1.4		%
Expected price volatility range	43.82% - 46.70%			43.42% - 43.66%			36.8% - 36.8%
Weighted-average expected price volatility	43.9		%	43.4		%	36.8		%
Expected dividend yield	—		%	—		%	0.37		%
Expected term in years at the date of grant	4.5			4.5			4.5

Stock option transactions under the terms of the LTSIP are summarized below:

	Options Outstanding		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
			(per share)		(in years)	(in millions)
Outstanding at December 31, 2016	2,151,957		$	25.26
Granted	418,752		16.77
Forfeited	(14,172	)	15.33
Cancelled	(202,260	)	27.55
Outstanding at December 31, 2017	2,354,277		$	23.62	3.50	$	—
Options Exercisable at December 31, 2017	1,551,861		$	27.90	2.47	$	—
Unvested Options at December 31, 2017	802,416		$	15.33	5.48	$	—

During the years ended December 31, 2017 and 2016, there were no exercises of stock options. The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.1 million during the year ended December 31, 2015. There was no income tax impact for the year ended December 31, 2017. The Company realized an income tax benefit of $0.2 million for the year ended December 31, 2016 and $6.4 million of income tax expense for the year ended December 31, 2015. As of December 31, 2017, $1.6 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.04 years.

Restricted Share Awards

Restricted share award grants typically vest in equal installments over a three-year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The Company expenses forfeitures of restricted share awards as they occur. The total fair value of restricted share awards that vested during the years ended December 31, 2017, 2016 and 2015, was $18.4 million, $24.3 million and $22.7 million, respectively. There was no income tax impact for the year ended December 31, 2017 and 2016. The Company realized an income tax benefit of $3.2 million for the year ended December 31, 2015. The weighted-average grant date fair value of restricted share awards granted was $13.90 per share, $10.50 per share and $20.92 per share for the years ended December 31, 2017, 2016 and 2015, respectively. As of December 31, 2017, $19.2 million of unrecognized compensation cost related to restricted share awards granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 1.99 years.

106

Transactions involving restricted share awards under the terms of the LTSIP are summarized below:

	Restricted Share Awards Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2016	3,208,503		$	14.32
Granted	2,219,763		13.90
Vested	(1,392,043	)	16.53
Forfeited	(314,889	)	14.49
Unvested balance at December 31, 2017	3,721,334		$	13.23

Performance Share Units

The payouts for performance share units are dependent upon the Company's total shareholder return compared to a group of its peers over a three-year period. The awards are denominated in share units and have historically been paid in cash. Beginning with awards granted in 2015, the Company has the option to settle earned awards in cash or shares of common stock under the Company's LTSIP; however, as of December 31, 2017, the Company expects to settle all awards in cash. These awards are classified as liabilities and are included within "Other long-term liabilities" on the Consolidated Balance Sheets. As these awards are dependent upon the Company's total shareholder return and stock price, they are measured at fair value at the end of each reporting period. The Company paid $5.3 million, $2.8 million and $3.1 million for vested performance share units during the years ended December 31, 2017, 2016 and 2015, respectively. The weighted-average grant date fair value of the performance share units granted during the years ended December 31, 2017, 2016 and 2015, was $16.90, $10.16, and $21.69 per share, respectively. As of December 31, 2017, $1.2 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 1.89 years.

Transactions involving performance share units under the terms of the CIP are summarized below:

	Performance Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2016	1,027,280		$	17.24
Granted	405,014		16.90
Vested and paid	(215,439	)	31.63
Forfeited	(17,519	)	13.88
Unvested balance at December 31, 2017	1,199,336		$	14.59

Restricted Share Units

Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. These awards are ultimately delivered in cash. They are classified as liabilities in "Other long-term liabilities" on the Consolidated Balance Sheets and are measured at fair value at the end of each reporting period. The weighted-average grant date fair value of the restricted share units was $16.98 and $10.12 per share for the years ended December 31, 2017 and 2016, respectively. As of December 31, 2017, $0.1 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 1.03 years.

107

Transactions involving restricted share units under the terms of the LTSIP are summarized below:

	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2016	18,034		$	10.12
Granted	9,924		16.98
Vested	(6,012	)	10.12
Unvested balance at December 31, 2017	21,946		$	13.22

Note 11 – Employee Benefits

Pension and other postretirement benefits

The Company provides pension and other postretirement benefits to certain employees through three retirement benefit plans: the QEP Resources, Inc. Retirement Plan (the Pension Plan), the Supplemental Executive Retirement Plan (the SERP), and a postretirement medical plan (the Medical Plan).

The Pension Plan is a closed, qualified, defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees, which, as of December 31, 2017, covers 30 active and suspended participants, or 5%, of QEP's active employees, and 184 participants that are retired or were terminated and vested. Pension Plan benefits are based on the employee's age at retirement, years of service as of the earlier of the participant's termination of employment or December 31, 2015, and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding termination of employment or, if earlier, December 31, 2015. During the year ended December 31, 2017, the Company made contributions of $4.0 million to the Pension Plan and expects to contribute approximately $4.0 million to the Pension Plan in 2018. Contributions to the Pension Plan increase plan assets. Due to the Pension Plan freeze on January 1, 2016, the Company began making additional contributions for eligible employees who were active participants in the Pension Plan on December 31, 2015 based on the eligible employee's age as of December 31, 2015. During the year ended December 31, 2017, QEP contributed $0.4 million for these employees.

As a result of the Company's 2014 divestitures and retirements in 2015, the number of active participants in the Pension Plan fell to 50 participants during the year ended December 31, 2015, which is the minimum number of active participants for a plan to meet the qualification requirements of the minimum participation rules under the Internal Revenue Code. In order to prevent disqualification, the Pension Plan was amended in June 2015 and was frozen effective January 1, 2016, such that employees do not earn additional defined benefits for future services except for purposes of determining eligibility for an early retirement benefit. This change resulted in a non-cash curtailment loss of $11.2 million recognized on the Consolidated Statements of Operations within "Interest and other income (expense)" expense during the year ended December 31, 2015. A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for present employees' future services.

The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. SERP benefits are based on the employee's age at retirement, years of service and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding the participant's termination of employment. During the year ended December 31, 2017, the Company made contributions of $2.0 million to its SERP and expects to contribute approximately $0.7 million in 2018. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and is closed to new participants effective January 1, 2016.

During the year ended December 31, 2017, the Company recognized a $0.7 million loss on curtailment related to the SERP in connection with the Pinedale Divestiture, which was recorded on the Consolidated Statements of Operations within "Net gain (loss) from asset sales".

108

The Medical Plan is a self-insured plan. It is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired QEP employees. The Medical Plan was originally provided only to employees hired by Questar Corporation before January 1, 1997. Of the 30 active, pension eligible employees, 17 are also eligible for the Medical Plan when they retire. As of December 31, 2017, 55 retirees are enrolled in the Medical Plan. The Company has capped its exposure to increasing medical costs by paying a fixed dollar monthly contribution toward these retiree benefits. The Company's contribution is prorated based on an employee's years of service at retirement; only those employees with 25 or more years of service receive the maximum company contribution. During the year ended December 31, 2017, the Company made contributions of $0.1 million and expects to contribute approximately $0.3 million of benefits in 2018. At December 31, 2017 and 2016, QEP's accumulated benefit obligation exceeded the fair value of its qualified retirement plan assets.

In February 2017, the Company changed the eligibility requirements for active employees eligible for the Medical Plan, as well as retirees currently enrolled. Effective July 1, 2017, the Company no longer offers the Medical Plan to a retiree and spouse that are both Medicare eligible. In addition, the Company no longer offers life insurance to individuals retiring on or after July 1, 2017.

In accordance with the early adoption of ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, the Company recast years ended December 31, 2016 and 2015 by recognizing service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of Operations. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations.

The accumulated benefit obligation for all defined-benefit pension plans was $128.7 million and $124.5 million at December 31, 2017 and 2016, respectively.

109

The following table sets forth changes in the benefit obligations and fair value of plan assets for the Company's Pension Plan, SERP and Medical Plan for the years ended December 31, 2017 and 2016, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2017 and 2016:

	Pension Plan and SERP benefits						Medical Plan benefits
	2017			2016			2017			2016
Change in benefit obligation	(in millions)
Benefit obligation at January 1,	$	129.2		$	120.3		$	5.4		$	5.2
Service cost	0.8			1.2			—			—
Interest cost	4.7			5.2			0.1			0.2
Curtailments	(0.3		)	—			—			—
Benefit payments	(6.9		)	(7.8		)	(0.1		)	(0.4		)
Plan amendments	—			—			(2.4		)	—
Actuarial loss (gain)	2.5			10.3			(0.1		)	0.4
Benefit obligation at December 31,	$	130.0		$	129.2		$	2.9		$	5.4
Change in plan assets
Fair value of plan assets at January 1,	$	86.1		$	79.3		$	—		$	—
Actual return on plan assets	15.3			7.4			—			—
Company contributions to the plan	6.0			7.2			0.1			0.4
Benefit payments	(6.9		)	(7.8		)	(0.1		)	(0.4		)
Fair value of plan assets at December 31,	100.5			86.1			—			—
Underfunded status (current and long-term)	$	(29.5	)	$	(43.1	)	$	(2.9	)	$	(5.4	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(1.5	)	$	(2.5	)	$	(0.2	)	$	(0.3	)
Other long-term liabilities	(27.9		)	(40.6		)	(2.6		)	(5.1		)
Total amount recognized in balance sheet	$	(29.4	)	$	(43.1	)	$	(2.8	)	$	(5.4	)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	15.0		$	23.5		$	(0.5	)	$	(0.4	)
Prior service cost	1.2			2.9			(1.2		)	1.0
Total amount recognized in AOCI	$	16.2		$	26.4		$	(1.7	)	$	0.6

110

The following table sets forth the Company's Pension Plan, SERP and Medical Plan cost and amounts recognized in other comprehensive income (before tax) for the respective years ended December 31:

	Pension Plan and SERP benefits									Medical Plan benefits
	2017			2016			2015			2017			2016			2015
Components of net periodic benefit cost	(in millions)
Service cost	$	0.8		$	1.2		$	2.1		$	—		$	—		$	—
Interest cost	4.7			5.2			4.9			0.1			0.2			0.2
Expected return on plan assets	(5.4		)	(5.6		)	(5.7		)	—			—			—
Curtailment loss	0.7			—			11.2			—			—			—
Settlements	0.2			—			—			—			—			—
Amortization of prior service costs	1.0			1.1			1.7			(0.3		)	0.2			0.2
Amortization of actuarial loss	0.5			0.8			0.5			(0.1		)	—			—
Periodic expense	$	2.5		$	2.7		$	14.7		$	(0.3	)	$	0.4		$	0.4
Components recognized in accumulated other comprehensive income
Current period prior service cost	$	(0.7	)	$	—		$	0.9		$	(2.5	)	$	—		$	—
Current period actuarial (gain) loss	(7.5		)	8.5			2.2			(0.1		)	0.4			(1.4		)
Amortization of prior service cost	(1.0		)	(1.1		)	(12.9		)	0.3			(0.2		)	(0.2		)
Amortization of actuarial gain (loss)	(0.5		)	(0.8		)	(0.5		)	0.1			—			—
Loss on curtailment in current period	(0.3		)	—			(7.1		)	—			—			—
Settlements	(0.2		)	—			—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	(10.2	)	$	6.6		$	(17.4	)	$	(2.2	)	$	0.2		$	(1.6	)

The Company recognizes service costs related to SERP and Medical Plan benefits on the Consolidated Statements of Operations within "General and administrative" expense. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized on the Consolidated Statements of Operations within "Interest and other income (expense)".

The estimated portion of net actuarial loss and net prior service cost for the Pension Plan and SERP that will be amortized from AOCI into net periodic benefit cost in 2018 is $1.9 million, which represents amortization of prior service cost recognized and actuarial losses. The estimated portion of net actuarial loss and net prior service cost for the Medical Plan that will be amortized from AOCI into net periodic benefit cost in 2018 is $0.3 million, which represents amortization of prior service cost recognized and actuarial gains. Amortization of prior service costs and actuarial gains or losses out of AOCI are recognized in the Consolidated Statements of Operations in "Interest and other income (expense)".

Following are the weighted-average assumptions (weighted by the plan level benefit obligation for pension benefits) used by the Company to calculate the Pension Plan, SERP and Medical Plan obligations at December 31, 2017 and 2016:

	Pension Plan and SERP benefits				Medical Plan benefits
	2017		2016		2017		2016
Discount rate	3.52	%	3.96	%	3.60	%	4.10	%
Rate of increase in compensation(1)	3.50	%	3.50	%	n/a		3.50	%

_______________________

⁽¹⁾   The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the years ended December 31, 2017 and 2016, the rate of increase in compensation only includes the SERP and Medical Plan.

The discount rate assumptions used by the Company represents an estimate of the interest rate at which the Pension Plan, SERP and Medical Plan obligations could effectively be settled on the measurement date.

111

Following are the weighted-average assumptions (weighted by the net period benefit cost for pension benefits) used by the Company in determining the net periodic Pension Plan, SERP and Medical Plan cost for the years ended December 31:

	Pension Plan and SERP benefits						Medical Plan benefits
	2017		2016		2015		2017		2016		2015
Discount rate	4.00	%	4.23	%	3.94	%	4.10	%	4.40	%	4.00	%
Expected long-term return on plan assets	6.00	%	6.50	%	6.75	%	n/a		n/a		n/a
Rate of increase in compensation(1)	3.50	%	4.00	%	4.00	%	3.50	%	4.00	%	4.00	%

_______________________

⁽¹⁾   The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the years ended December 31, 2017 and 2016, the rate of increase in compensation only includes the SERP and Medical Plan.

In selecting the assumption for expected long-term rate of return on assets, the Company considers the average rate of return expected on the funds to be invested to provide benefits. This includes considering the plan's asset allocation, historical returns on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the plan. No plan assets are expected to be returned to the Company in 2018. Historical health care cost trend rates are not applicable to the Company, because the Company's medical costs are capped at a fixed amount. As the Company's medical costs are capped at a fixed amount, the sensitivity to increases and decreases in the health-care inflation rate is not applicable.

Plan Assets

The Company's Employee Benefits Committee (EBC) oversees investment of qualified pension plan assets. The EBC uses a third-party asset manager to assist in setting targeted-policy ranges for the allocation of assets among various investment categories. The EBC allocates pension plan assets among broad asset categories and reviews the asset allocation at least annually. Asset allocation decisions consider risk and return, future-benefit requirements, participant growth and other expected cash flows. These characteristics affect the level, risk and expected growth of postretirement-benefit assets. The EBC uses asset-mix guidelines that include targets for each asset category, return objectives for each asset group and the desired level of diversification and liquidity. These guidelines may change from time to time based on the EBC's ongoing evaluation of each plan's risk tolerance. The EBC estimates an expected overall long-term rate of return on assets by weighting expected returns of each asset class by its targeted asset allocation percentage. Expected return estimates are developed from analysis of past performance and forecasts of long-term return expectations by third-parties. Responsibility for individual security selection rests with each investment manager, who is subject to guidelines specified by the EBC. The EBC sets performance objectives for each investment manager that are expected to be met over a three-year period or a complete market cycle, whichever is shorter. Performance and risk levels are regularly monitored to confirm policy compliance and that results are within expectations. Performance for each investment is measured relative to the appropriate index benchmark for its category. QEP securities may be considered for purchase at an investment manager's discretion, but within limitations prescribed by the Employee Retirement Income Security Act of 1974 (ERISA) and other laws. There was no direct investment in QEP shares for the periods disclosed. The majority of retirement-benefit assets were invested as follows:

Equity securities:Domestic equity assets were invested in a combination of index funds and actively managed products, with a diversification goal representative of the whole U.S. stock market. International equity securities consisted of developed and emerging market foreign equity assets that were invested in funds that hold a diversified portfolio of common stocks of corporations in developed and emerging foreign countries.

Debt securities: Investment grade intermediate-term debt assets are invested in funds holding a diversified portfolio of debt of governments, corporations and mortgage borrowers with average maturities of five to ten years and investment grade credit ratings. Investment grade long-term debt assets are invested in a diversified portfolio of debt of corporate and non-corporate issuers, with an average maturity of more than ten years and investment grade credit ratings. High yield and bank loan assets are held in funds holding a diversified portfolio of these instruments with an average maturity of five to seven years.

Although the actual allocation to cash and short-term investments is minimal (less than 5%), larger cash allocations may be held from time to time if deemed necessary for operational aspects of the retirement plan. Cash is invested in a high-quality, short-term temporary investment fund that purchases investment-grade quality short-term debt issued by governments and corporations.

112

The EBC made the decision to invest all of the retirement plan assets in commingled funds as these funds typically have lower expense ratios and are more tax efficient than mutual funds. These investments are public investment vehicles valued using the net asset value (NAV) as a practical expedient. The NAV is based on the underlying assets owned by the fund excluding transaction costs and minus liabilities, which can be traced back to observable asset values. No assets held by the Pension Plan that were valued using the NAV methodology were subject to redemption restrictions on their valuation date. These commingled funds are audited annually by an independent accounting firm.

In conjunction with the issuance of ASU 2015-07, Fair Value Measurements (Topic 820): Disclosures for Investment in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), QEP no longer presents its Pension Plan assets in the fair value hierarchy, in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures, as all investments are measured at NAV as a practical expedient, which are now required to be excluded from the fair value hierarchy.

The following table summarizes investments for which fair value is measured using the NAV per share practical expedient as of December 31, 2017 and 2016, respectively:

	December 31, 2017				December 31, 2016
	Total		Percentage of total		Total		Percentage of total
	(in millions, except percentages)
Cash and short-term investments	$	0.5	—	%	$	3.5	4	%
Equity securities:
Domestic	35.0		35	%	39.3		46	%
International	15.3		15	%	21.6		25	%
Fixed income	49.7		50	%	21.7		25	%
Total investments	$	100.5	100	%	$	86.1	100	%

Expected Benefit Payments

As of December 31, 2017, the following future benefit payments are expected to be paid:

	Pension Plan and SERP benefits		Medical Plan benefits
	(in millions)
2018	$	6.6	$	0.2
2019	$	8.1	$	0.2
2020	$	7.6	$	0.2
2021	$	8.3	$	0.2
2022	$	6.8	$	0.2
2023 through 2026	$	39.1	$	0.6

113

Employee Investment Plan

QEP employees may participate in the QEP Employee Investment Plan, a defined-contribution plan (the 401(k) Plan). The 401(k) Plan allows eligible employees to make investments, including purchasing shares of QEP common stock, through payroll deduction at the current fair market value on the transaction date. Participants receive 100% employer matching contributions on participant 401(k) plan contributions up to a percentage of qualifying earnings as described below.

	Year Ended December 31,
	2017		2016		2015
Employees not covered by the Pension Plan or SERP(1)
Maximum employer matching of qualifying earnings	8	%	8	%	8	%
Employees covered by the Pension Plan but not the SERP(1)
Maximum employer matching of qualifying earnings	8	%	8	%	6	%
Employees covered by both the Pension Plan and the SERP(1)
Maximum employer matching of qualifying earnings	6	%	6	%	6	%

_______________________

⁽¹⁾  The Pension Plan was frozen effective January 1, 2016.

The Company may contribute a discretionary portion beyond the Company's matching contribution to employees not in the Pension Plan or SERP. The Company recognizes expense equal to its yearly contributions, which amounted to $6.0 million, $5.6 million and $6.3 million during the years ended December 31, 2017, 2016 and 2015, respectively.

Note 12 – Income Taxes

On December 22, 2017 the Tax Cuts and Jobs Act (H.R.1) (Tax Legislation) was signed into law, which resulted in significant changes to U.S. federal income tax law. QEP expects that these changes will positively impact QEP's future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate of 21% compared to 35%. The Tax Legislation also repeals the corporate alternative minimum tax (AMT). Several provisions of the new tax law such as limitations on the deductibility of interest expense and certain executive compensation and the inability to use Section 1031 like-kind exchanges for assets such as machinery and equipment could apply to QEP; however, we do not believe that they will materially impact QEP's financial statements. The impact of the Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made and actions the Company may take as a result of the Tax Legislation.  Additionally, guidance issued by the relevant regulatory authorities regarding the Tax Legislation may materially impact QEP's financial statements. The Company will continue to analyze the Tax Legislation to determine the full impact of the new law, on the Company's consolidated financial statements and operations.

Details of income tax provisions and deferred income taxes from continuing operations are provided in the following tables.

The components of income tax provisions and benefits were as follows:

	Year Ended December 31,
	2017			2016			2015
Federal income tax provision (benefit)	(in millions)
Current	$	2.1		$	(55.5	)	$	(112.3	)
Deferred	(339.8		)	(614.3		)	34.5
State income tax provision (benefit)
Current	0.5			(1.5		)	(6.6		)
Deferred	25.0			(36.9		)	(9.2		)
Total income tax provision (benefit)	$	(312.2	)	$	(708.2	)	$	(93.6	)

114

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

	Year Ended December 31,
	2017		2016		2015
Federal income taxes statutory rate	35.0	%	35.0	%	35.0	%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit(1)	(40.1	)%	2.4	%	4.2	%
Federal rate change(2)	741.3	%	—	%	—	%
State rate change	2.1	%	(1.1	)%	—	%
Penalties	(0.4	)%	—	%	(0.3	)%
Return to provision adjustment	(0.7	)%	—	%	(0.3	)%
Uncertain tax provision (federal rate change)	(7.7	)%	—	%	—	%
Other	(1.8	)%	—	%	(0.1	)%
Effective income tax rate	727.7	%	36.3	%	38.5	%

____________________________

⁽¹⁾  State income taxes changed significantly from prior years mainly due to the change in valuation allowance during the year of $36.2 million.

⁽²⁾  The new tax legislation changed the federal corporate income tax rate from 35% to 21% starting in 2018. The rate change caused the Company to revalue its deferred tax liabilities and assets as of December 31, 2017 from a 35% to 21% federal corporate income tax rate which caused the majority of the change in rate.

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

	December 31,
	2017(1)		2016
Deferred tax liabilities	(in millions)
Property, plant and equipment	$	898.7	$	1,135.0
Deferred tax assets
Net operating loss and tax credit carryforwards	$	308.8	$	161.6
Employee benefits and compensation costs	26.4		49.0
Bonus and vacation accrual	6.2		11.4
Commodity price derivatives	29.9		74.3
Other	9.4		12.8
Total deferred tax assets	380.7		309.1
Net deferred income tax liability	$	518.0	$	825.9
Balance sheet classification
Deferred income tax liability – noncurrent	518.0		825.9
Net deferred income tax liability	$	518.0	$	825.9

____________________________

⁽¹⁾  The $307.9 million decrease in net deferred income tax liability as of December 31, 2017 is primarily related to a $318.0 million decrease from the federal rate change from 35% to 21%.

115

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2017, are as follows:

	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2018-2037	$	95.8
State net operating loss valuation allowance		$	(56.8	)
U.S. net operating loss	2036-2037	$	250.4
U.S. alternative minimum tax credit	Indefinite	$	19.5

The valuation allowance of $56.8 million was established in 2014 and 2017 against the available state net operating loss and is related primarily to losses incurred in Oklahoma and Louisiana. Due to the 2014 property sales in the Other Southern area in which the Company sold its interests in most of its properties in Oklahoma, the Company does not forecast sufficient taxable income to utilize the net operating loss in Oklahoma. In 2017, a valuation allowance of $31.8 million was established against Louisiana's net operating loss as the Company does not forecast sufficient taxable income to utilize the entire net operating loss in Louisiana.

The Tax Legislation eliminated AMT, and allowed the ability to offset our regular tax liability or claim refunds for taxable years 2018 through 2021 for AMT credits carried forward from prior years. The Company currently anticipates it will realize approximately $19.5 million in AMT value over the next four years with approximately half of this value estimated to be realized in 2019 for taxable year 2018.

Unrecognized Tax Benefit

As of December 31, 2017 and 2016, QEP had $19.0 million and $15.6 million, respectively, of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which were recorded within "Other long-term liabilities" on the Consolidated Balance Sheets. The $15.6 million uncertain tax position the Company reported during the year ended December 31, 2016, was expensed during the year ended December 31, 2014, with an additional $3.4 million expensed during the year ended December 31, 2017 with the new Tax Legislation. The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authorities. Our policy is to recognize any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statements of Operations and to recognize any penalties related to uncertain tax positions in "General and administrative" expense on the Consolidated Statements of Operations. During the year ended December 31, 2017, the Company incurred $0.7 million of estimated interest expense related to uncertain tax positions. During the year ended December 31, 2016, the Company incurred $0.7 million of estimated interest expense and $0.6 million of estimated penalties related to uncertain tax positions.

The following is a reconciliation of our beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2017 and 2016:

	Unrecognized Tax Benefits
	2017		2016
	(in millions)
Balance as of January 1,	$	15.6	$	15.6
Federal benefit of state (change from 35% to 21%)	3.4		—
Balance as of December 31,	$	19.0	$	15.6

As of December 31, 2017 and 2016, QEP had approximately $19.0 million and $15.6 million, respectively, of unrecognized tax benefit that would impact its effective tax rate if recognized. The difference is due to the change in the Federal tax rate in 2017 from 35% to 21%, which affects the federal benefit of the state deduction to the unrecognized tax position.

116

Note 13 – Quarterly Financial Information (unaudited)

The following table provides a summary of unaudited quarterly financial information:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Year
2017	(in millions, except per share amounts or otherwise specified)
Revenues	$	420.1		$	383.7		$	390.1		$	429.0		$	1,622.9
Operating income (loss)	(5.2		)	(0.9		)	132.1			(24.5		)	101.5
Net income (loss)	76.9			45.4			(3.3		)	150.3			269.3
Net gain (loss) from asset sales and impairment	(0.1		)	19.8			157.1			(42.2		)	134.6
Nonrecurring items in operating income (loss)(1)	—			—			8.2			—			8.2
Per share information
Basic EPS	$	0.32		$	0.19		$	(0.01	)	$	0.62		$	1.12
Diluted EPS	0.32			0.19			(0.01		)	0.62			1.12
Production information
Total equivalent production (Mboe)	13,090.3			13,860.6			14,124.1			12,069.9			53,144.9
Total equivalent production (Bcfe)	78.6			83.2			84.7			72.1			318.6

2016
Revenues	$	261.3		$	333.7		$	382.4		$	399.7		$	1,377.1
Operating income (loss)	(1,379.0		)	(92.1		)	(93.1		)	(36.5		)	(1,600.7		)
Net income (loss)	(863.8		)	(197.0		)	(50.9		)	(133.3		)	(1,245.0		)
Net gain (loss) from asset sales and impairment	(1,181.9		)	(1.6		)	0.3			(6.1		)	(1,189.3		)
Nonrecurring items in operating income (loss)(1)	7.7			—			25.0			—			32.7
Per share information
Basic EPS	$	(4.55	)	$	(0.90	)	$	(0.21	)	$	(0.56	)	$	(5.62	)
Diluted EPS	(4.55		)	(0.90		)	(0.21		)	(0.56		)	(5.62		)
Production information
Total equivalent production (Mboe)	13,776.4			13,882.4			14,445.7			13,675.7			55,780.2
Total equivalent production (Bcfe)	82.7			83.3			86.6			82.1			334.7

____________________________

⁽¹⁾  Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017 and 2016.

Note 14 – Supplemental Oil and Gas Information (unaudited)

The Company is making the following supplemental disclosures of oil and gas producing activities, in accordance with ASC 932, Extractive Activities – Oil and Gas, as amended by ASU 2010-03, Oil and Gas Reserve Estimation and Disclosures, and SEC Regulation S-X. The Company uses the successful efforts accounting method for its oil and gas exploration and development activities. All of QEP's properties are located in the United States.

117

Capitalized Costs

The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below:

	December 31,
	2017			2016
	(in millions)
Proved properties	$	12,470.9		$	14,232.5
Unproved properties, net	1,095.8			871.5
Total proved and unproved properties	13,566.7			15,104.0
Accumulated depreciation, depletion and amortization	(6,642.9		)	(8,797.7		)
Net capitalized costs	$	6,923.8		$	6,306.3

Costs Incurred

The costs incurred in oil and gas acquisition, exploration and development activities are displayed in the table below. Development costs are net of the change in accrued capital costs of $60.6 million and ARO additions and revisions of $32.0 million during the year ended December 31, 2017. The costs incurred for the development of reserves that were classified as proved undeveloped were approximately $389.3 million in 2017, $258.1 million in 2016, and $490.4 million in 2015.

	Year Ended December 31,
	2017		2016		2015
	(in millions)
Proved property acquisitions	$	269.6	$	431.6	$	49.6
Unproved property acquisitions	532.4		208.7		39.8
Other acquisitions	13.2		—		—
Exploration costs (capitalized and expensed)	32.7		13.4		8.7
Development costs	1,189.3		509.2		1,010.3
Total costs incurred	$	2,037.2	$	1,162.9	$	1,108.4

Results of Operations

Following are the results of operations of QEP's oil and gas producing activities, before allocated corporate overhead and interest expenses.

	Year Ended December 31,
	2017			2016			2015
	(in millions)
Revenues	$	1,548.1		$	1,271.0		$	1,390.4
Production costs	675.4			616.7			654.1
Exploration expenses	22.0			1.7			2.7
Depreciation, depletion and amortization	735.1			852.3			870.8
Impairment	72.3			1,194.3			55.6
Total expenses	1,504.8			2,665.0			1,583.2
Income (loss) before income taxes	43.3			(1,394.0		)	(192.8		)
Income tax benefit (expense)	(16.0		)	517.2			70.6
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	27.3		$	(876.8	)	$	(122.2	)

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Estimated Quantities of Proved Oil and Gas Reserves

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 oversight of a multi-functional Reserves Review Committee reporting to the Company's Audit Committee of the Board of Directors. The Company retained Ryder Scott Company, L.P. (RSC), independent oil and gas reserve evaluation engineering consultants, to prepare the estimates of all of its proved reserves as of December 31, 2017 and 2016, and retained RSC and DeGolyer and MacNaughton to prepare the estimates of all of its proved reserves as of December 31, 2015. The estimated proved reserves have been prepared in accordance with the SEC's Regulation S-X and ASC 932 as amended. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

All of QEP's proved undeveloped reserves at December 31, 2017, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves. The Company plans to continue development of its leaseholds and anticipates that it will have the financial capability to continue development in the manner estimated. While the majority of QEP's PUD reserves are located on leaseholds that are held by production, any PUD locations on expiring leaseholds are scheduled for development during the primary term of the lease.

119

As of December 31, 2017, all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's change in quantities of proved oil, gas and NGL reserves for the years ended December 31, 2015, 2016 and 2017 are as follows:

	Oil		Gas		NGL		Total(13)
	(MMbbl)		(Bcf)		(MMbbl)		(MMboe)
Balance at December 31, 2014	172.5		2,317.2		96.6		655.3
Revisions of previous estimates(1)	(47.0	)	(463.8	)	(55.3	)	(179.6	)
Extensions and discoveries(2)	85.6		467.7		21.8		185.4
Purchase of reserves in place(3)	2.0		3.2		0.6		3.1
Sale of reserves in place(4)	(0.4	)	(34.3	)	(0.2	)	(6.3	)
Production	(19.6	)	(181.1	)	(4.7	)	(54.5	)
Balance at December 31, 2015	193.1		2,108.9		58.8		603.4
Revisions of previous estimates(5)	(9.7	)	412.8		(0.3	)	58.8
Extensions and discoveries(6)	13.0		158.1		3.3		42.6
Purchase of reserves in place(7)	62.7		54.6		11.5		83.3
Sale of reserves in place(8)	(0.2	)	(3.6	)	(0.1	)	(0.9	)
Production	(20.3	)	(177.0	)	(6.0	)	(55.8	)
Balance at December 31, 2016	238.6		2,553.8		67.2		731.4
Revisions of previous estimates(9)	3.7		12.5		(3.1	)	2.7
Extensions and discoveries(10)	59.1		101.9		10.4		86.4
Purchase of reserves in place(11)	46.6		125.5		8.7		76.3
Sale of reserves in place(12)	(7.9	)	(831.2	)	(12.6	)	(159.0	)
Production	(19.6	)	(168.9	)	(5.4	)	(53.1	)
Balance at December 31, 2017	320.5		1,793.6		65.2		684.7
Proved developed reserves
Balance at December 31, 2014	99.3		1,288.4		52.2		366.2
Balance at December 31, 2015	109.7		1,245.3		34.4		351.6
Balance at December 31, 2016	103.2		1,309.8		35.7		357.2
Balance at December 31, 2017	116.0		655.5		27.9		253.1
Proved undeveloped reserves
Balance at December 31, 2014	73.2		1,028.8		44.4		289.1
Balance at December 31, 2015	83.4		863.6		24.4		251.8
Balance at December 31, 2016	135.4		1,244.0		31.5		374.2
Balance at December 31, 2017	204.5		1,138.1		37.3		431.6

___________________________

⁽¹⁾  Revisions of previous estimates in 2015 include: 126.2 MMboe of negative revisions due to lower pricing and 67.2 MMboe of negative revisions unrelated to pricing, partially offset by 13.7 MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and the Uinta Basin.

⁽²⁾  Extensions and discoveries in 2015 increased proved reserves by 185.4 MMboe, primarily related to extensions and discoveries in the Williston Basin of 68.2 MMboe, the Uinta Basin of 53.2 MMboe, and the Permian Basin of 49.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations.

⁽³⁾  Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP operated wells in the Williston and Permian basins as discussed in Note 2 – Acquisitions and Divestitures.

⁽⁴⁾  Sale of reserves in place in 2015 relate to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures.

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⁽⁵⁾  Revisions of previous estimates in 2016 include 77.3 MMboe of positive revisions, primarily related to successful workovers in Haynesville/Cotton Valley; reserves associated with increased density wells in areas that have been previously developed on lower density spacing; and 5.5 MMboe of positive performance revisions. These positive revisions were partially offset by 18.5 MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices.

⁽⁶⁾  Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations.

⁽⁷⁾  Purchase of reserves in place in 2016 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.

⁽⁸⁾  Sale of reserves in place in 2016 relates to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures.

⁽⁹⁾  Revisions of previous estimates in 2017 include 2.7 MMboe of positive revisions, primarily related to 32.0 MMboe of positive revisions related to pricing, driven by higher oil, gas and NGL prices and 2.2 MMboe of positive performance revisions. These positive revisions were partially offset by 11.0 MMboe of negative revisions related to higher operating costs and 20.5 MMboe of other revisions primarily from changing to a horizontal development plan from a vertical well development plan in the Uinta Basin and increased longer laterals in Haynesville/Cotton Valley. These negative other revisions are partially offset by positive other revisions from successful infill drilling in Haynesville/Cotton Valley and the Williston Basin.

⁽¹⁰⁾  Extensions and discoveries in 2017 primarily related to new well completions and associated new PUD locations in the Permian Basin.

⁽¹¹⁾  Purchase of reserves in place in 2017 was primarily related to QEP's 2017 Permian Basin Acquisition and various other acquired oil and gas properties as discussed in Note 2 – Acquisitions and Divestitures.

⁽¹²⁾  Sale of reserves in place in 2017 was primarily related to QEP's Pinedale Divestiture as discussed in Note 2 – Acquisitions and Divestitures.

⁽¹³⁾  Generally, gas consumed in operations was excluded from reserves, however, in some cases, produced gas consumed in operations was included in reserves when the volumes replaced fuel purchases.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

Future net cash flows were calculated at December 31, 2017, 2016 and 2015, by applying prices, which were the simple average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for each of the 12 months during 2017, 2016 and 2015, with consideration of known contractual price changes. The prices used do not include any impact of QEP's commodity derivatives portfolio. The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:

	For the year ended December 31,
	2017		2016		2015
Average benchmark price per unit:
Oil price (per bbl)	$	51.34	$	42.75	$	50.28
Gas price (per MMBtu)	$	2.98	$	2.48	$	2.59

Year ended operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop proved undeveloped reserves are approximately $486.5 million in 2018, $710.0 million in 2019 and $1,006.2 million in 2020. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. QEP believes cash flow from its operating activities, cash on hand and borrowings under its revolving credit facility will be sufficient to cover these estimated future development costs. In addition, QEP estimates that its future development costs relating to wells waiting on completion and its refracturing program, which are not classified as PUD, are approximately $132.6 million in 2018.

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The assumptions used to derive the standardized measure of discounted future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes but should not be solely relied upon in evaluating QEP or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below:     

• Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations.

• Future operating and capital costs will likely differ from those required to be used in these calculations.

• Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and gas may cause production rates in future years to vary significantly from those rates used in the calculations.

• Future revenues may be subject to different production, severance and property taxation rates.

• The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.

The standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below:

	Year Ended December 31,
	2017			2016			2015
	(in millions)
Future cash inflows	$	22,028.9		$	16,239.8		$	15,325.3
Future production costs	(9,074.2		)	(7,789.0		)	(7,389.9		)
Future development costs(1)	(4,726.0		)	(3,432.9		)	(2,202.5		)
Future income tax expenses(2)	(1,439.1		)	(913.4		)	(1,169.3		)
Future net cash flows	6,789.6			4,104.5			4,563.6
10% annual discount for estimated timing of net cash flows	(3,692.3		)	(2,176.5		)	(2,087.3		)
Standardized measure of discounted future net cash flows	$	3,097.3		$	1,928.0		$	2,476.3

___________________________

⁽¹⁾  Future development costs include future abandonment and salvage costs.

⁽²⁾  The standardized measure of discounted future net cash flows for the year ended December 31, 2017, assumes the new 21% federal tax rate from the Tax Legislation enacted in December 2017.

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The principal sources of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below:

	Year Ended December 31,
	2017			2016			2015
	(in millions)
Balance at January 1,	$	1,928.0		$	2,476.3		$	5,340.0
Sales of oil, gas and NGL produced, net of production costs	(872.7		)	(654.3		)	(736.3		)
Net change in sales prices and in production (lifting) costs related to future production	1,457.2			(739.4		)	(6,307.8		)
Net change due to extensions and discoveries	556.8			81.8			1,765.7
Net change due to revisions of quantity estimates	9.9			122.7			(1,350.2		)
Net change due to purchases of reserves in place	342.7			256.5			29.7
Net change due to sales of reserves in place	(504.7		)	(4.3		)	(48.8		)
Previously estimated development costs incurred during the period	475.4			374.6			865.0
Changes in estimated future development costs	(283.4		)	(476.5		)	560.7
Accretion of discount	235.7			311.1			752.9
Net change in income taxes	(227.4		)	205.4			1,554.4
Other	(20.2		)	(25.9		)	51.0
Net change	1,169.3			(548.3		)	(2,863.7		)
Balance at December 31,	$	3,097.3		$	1,928.0		$	2,476.3

Note 15 – Subsequent Event

In February 2018, in conjunction with the 2017 Permian Basin Acquisition, QEP entered into agreements to acquire oil and gas properties in the Permian Basin for an aggregate purchase price of $36.1 million, subject to customary purchase price adjustments. The transactions are expected to be funded with borrowings under the credit facility and are expected to close in the first half of 2018.

In February 2018, the Board of Directors approved a retention and severance program in conjunction with the announcement of several strategic initiatives, which include selling assets and focusing the Company's activities on its Permian Basin operations. The estimated amount of general and administrative expenses to be incurred related to this program in 2018 is approximately $20.0 million.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(b) under the Securities Exchange Act of 1934, as amended), as of December 31, 2017. Based on such evaluation, such officers have concluded that, as of December 31, 2017, the Company's disclosure controls and procedures are designed and effective to ensure that information required to be included in the Company's reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information required to be disclosed in the Company's reports filed or submitted under the Exchange Act is accumulated and communicated to the Company's management including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

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In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company's controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Control over Financial Reporting

There were no changes in the Company's internal control over financial reporting (as defined by Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2017, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Management's Assessment of Internal Control over Financial Reporting

The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f) and 15d-15(f). The Company's internal control over financial reporting is a process designed under the supervision of QEP's chief executive officer and chief financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted. Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Also, projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or processes may deteriorate.

As of December 31, 2017, management assessed the effectiveness of our internal control over financial reporting based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission for effective internal control over financial reporting. Based on the assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2017. Management included in its assessment of internal control over financial reporting all consolidated entities.

PricewaterhouseCoopers, LLP, the independent registered public accounting firm that audited the Consolidated Financial Statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of internal control over financial reporting as of December 31, 2017, which is included in the Consolidated Financial Statements in Item 8 of Part II of this Annual Report on Form 10-K.

ITEM 9B. OTHER INFORMATION

Approval of Executive Retention and Severance Compensation Program

On February 26, 2018, QEP's Board of Directors approved an executive severance compensation program, pursuant to which each of QEP's named executive officers have entered into an Executive Severance Compensation Program letter agreement (the Severance Letters). The Severance Letters provide that in the event the executive's employment with QEP is terminated without cause or the executive resigns his employment for good reason (as such terms are defined in the Severance Letters), and such termination or resignation occurs prior to September 30, 2020, the executive will be entitled to receive the following severance payments and benefits, subject to the execution and non-revocation of a release of claims agreement containing, among other terms, confidentiality and non-solicitation restrictions, and other customary conditions:

• A lump sum cash payment equal to 1.5 times (2.5 times for Mr. Stanley and 2.0 times for Mr. Doleshek) the sum of the executive's annual base salary and annual target bonus award opportunity;

• A pro-rated bonus award for the year of termination, which shall be at the target level for executives other than Mr. Stanley and Mr. Doleshek, which shall be based on actual performance for the year;

• Accelerated vesting of all outstanding equity and long-term incentive awards, provided that the vesting of performance-based awards is based on and subject to the actual level of performance in relation to applicable performance measures;

• A lump sum cash payment representing 24 months of premium payment amounts required to continue the executive's and the executive's covered dependents' medical, dental and vision coverage pursuant to COBRA; and

• For executives participating in the QEP Resources, Inc. Retirement Plan and/or the QEP Resources Inc. Supplemental Executive Retirement Plan, a cash payment representing two additional years of service credit under such plans.

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The severance benefits payable under the Severance Letters are in lieu of any other severance entitlements applicable to the participating executives, provided that in the event a change in control of QEP occurs during the term of the Severance Letters, the executives will not receive the benefits under the Severance Letters and will instead be eligible to receive the benefits provided under the QEP Resources, Inc. Executive Severance Compensation Plan - CIC, as previously adopted by the Board of Directors.

In addition, on February 26, 2018, QEP's Board of Directors approved an executive retention award program, pursuant to which each of QEP's named executive officers (other than Mr. Stanley and Mr. Doleshek) have entered into an Executive Retention Bonus letter agreement (the Retention Letters). The Retention Letters provide, for each of our named executive officers other than Mr. Stanley and Mr. Doleshek, for a one-time cash retention payment of $500,000, payable within 15 days after March 1, 2019, subject to continued employment through such date. If the executive's employment is terminated by QEP without cause or the executive resigns employment for good reason prior to such date, the executive will be eligible to receive a pro-rated amount of the retention payment.

The foregoing description of the Severance Letters and the Retention Letters is not complete and is qualified in its entirety by reference to the text of the full letter agreements, which are attached as Exhibits 10.29 and 10.30, respectively to this Form 10-K and are incorporated herein by reference.

Letter Agreement

On February 28, 2018, QEP entered into an agreement (the Agreement) with Elliott Management Corporation, a Delaware corporation (Elliott).

Under the terms of the Agreement, the Company agreed to issue a press release announcing, among other things, certain strategic initiatives, a copy of which was furnished as an exhibit to the Company's Form 8-K filed on February 28, 2018.

The Agreement also provides that the Company will include a proposal in its definitive proxy statement (the Proxy Statement) for its 2018 annual meeting (the Annual Meeting) asking the Company's shareholders to approve an amendment to the Company's Amended and Restated Certificate of Incorporation to immediately declassify the existing board structure and provide for the annual election of directors (the Declassification Amendment). The Company has agreed to recommend to its shareholders that they vote in favor of the Declassification Amendment. In connection with the Declassification Amendment, all of the current members of the Company's board of directors (the Board), other than Mr. Thacker, will tender their resignations on the date of the Annual Meeting, to be effective on such date. Should the Declassification Amendment be approved by the Company's shareholders, all of the directors shall serve until the 2019 annual meeting, including Mr. Thacker whose remaining term will expire at the 2019 annual meeting. If the Declassification Amendment is not approved, all of the directors, other than Mr. Thacker, shall be nominated to the class and for the term that they would have otherwise served prior to their resignation.

The Agreement also provides that at the Annual Meeting, Elliott will vote or cause to be voted any shares of common stock of the Company that it or certain of its affiliates have the right to vote, as of the record date, in favor of the election of directors nominated by the Company and in accordance with the recommendations of the Board on the other proposals in the Proxy Statement not related to an extraordinary transaction.

Elliott further agreed that, subject to certain exceptions, until the earlier of (i) January 15, 2019, and (ii) thirty (30) days prior to the first day of the time period established pursuant to the Company's bylaws for shareholders to deliver notice to the Company of director nominations to be brought before the 2019 annual meeting, not to, among other things and subject to certain exceptions: (a) make any "solicitation" of proxies (as such terms are used in the proxy rules of the Securities and Exchange Commission), (b) form, join or act in concert with any "group" as defined in Section 13(d)(3) of the United States Securities Exchange Act of 1934 (the Exchange Act), other than solely with affiliates of Elliott with respect to voting securities now or hereafter held by them, (c) acquire, offer or seek to acquire any voting securities of the Company that would result in Elliott having a net long position of, or voting rights with respect to, more than 9.9% of the voting securities of the Company, (d) effect or seek to effect, whether alone or in concert with others, any extraordinary transaction involving the Company, (e) enter into any voting trust or similar arrangement, (f) seek to (i) elect or appoint to, or have representation on, the Board or (ii) remove any member of the Board, (g) make or be the proponent of any shareholder proposal (pursuant to Rule 14a-8 under the Exchange Act or otherwise) or (h) enter into any discussions, negotiations, agreements or understandings with any third party with respect to the foregoing.

A copy of the Agreement is filed with this Form 10-K and attached hereto as Exhibit 10.31 and incorporated by reference herein. The foregoing description of the Agreement is qualified in its entirety by reference to the full text of the Agreement.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by Item 10 concerning QEP's directors and nominees for directors and other corporate governance matters will be presented in the Company's definitive Proxy Statement prepared for the solicitation of proxies in connection with the Company's Annual Meeting of Stockholders, which the Company expects to file with the Securities and Exchange Commission no later than 120 days subsequent to December 31, 2017 (Proxy Statement), and is incorporated by reference herein.

Information about the Company's executive officers can be found in Item 1 of Part I in this Annual Report on Form 10-K.

Information concerning compliance with Section 16(a) of the Exchange Act will be set forth in the Proxy Statement and is incorporated herein by reference.

The Company has a Code of Conduct that applies to all of its directors, officers (including its chief executive officer and chief financial officer) and employees. QEP has posted the Code of Conduct on its website, www.qepres.com. Any waiver of the Code of Conduct for executive officers must be approved by the Company's Board of Directors. QEP will post on its website any amendments to or waivers of the Code of Conduct that apply to executive officers.

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 will be set forth in the Proxy Statement and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by Item 12 will be set forth in the Proxy Statement and is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by Item 13 will be set forth in the Proxy Statement and is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by Item 14 will be set forth in the Proxy Statement and is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial statements and financial statement schedules filed as part of this report are listed in the index included in Item 8 of Part II Financial Statements and Supplementary Data of this report.

(b) Exhibits. The following is a list of exhibits required to be filed as a part of this report in Item 15(b).

Exhibit No.	Description
3.1	Amended and Restated Certificate of Incorporation dated May 17, 2017 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 18, 2017)
3.2	Amended and Restated Bylaws, dated effective October 23, 2017 (incorporated by reference to Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on October 25, 2017)
4.1	Indenture dated as of March 1, 2001, between Questar Market Resources, Inc. (predecessor-in-interest to QEP Resources, Inc.) and Bank One, NA, (predecessor-in-interest to Wells Fargo Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.01 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on March 13, 2001)

127

4.2	6.80% Notes due 2020 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on September 2, 2009)
4.3	Officers' Certificate, dated as of August 31, 2009, setting forth the terms of the 6.80% Notes due 2020 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on September 2, 2009)
4.4	Officers' Certificate, dated as of August 16, 2010 (including the form of the 6.875% Notes due 2021) (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2010)
4.5	Indenture, dated as of March 1, 2012, between the Company and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on March 1, 2012)
4.6	Officer's Certificate, dated as of March 1, 2012 (including the form of the 5.375% Notes due 2022) (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on March 1, 2012)
4.7	Officer's Certificate, dated as of September 12, 2012 (including form of the 5.250% Notes due 2023) (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on September 14, 2012)
4.8	Officer's Certificate, dated as of November 21, 2017 (including the form of the 5.625% Senior Notes due 2026) (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, filed with the Securities Exchange Commission on November 21, 2017)
10.1	Credit Agreement, dated as of August 25, 2011, among QEP Resources, Inc., Wells Fargo Bank, National Association, as the administrative agent, letter of credit issuer and swing line lender, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 29, 2011), as amended by the First Amendment to Credit Agreement, dated as of July 6, 2012, the Second Amendment to Credit Agreement, dated as of August 13, 2013 (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013), the Third Amendment to Credit Agreement, dated as of January 31, 2014 (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on May 7, 2014), the Fourth Amendment to Credit Agreement and Commitment Increase Agreement, dated as of December 2, 2014 (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 4, 2014), the Fifth Amendment to Credit Agreement, dated as of November 23, 2015 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on November 23, 2015), the Sixth Amendment to Credit Agreement, dated as of May 5, 2017 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 9, 2017), the Seventh Amendment to Credit Agreement, dated as of November 21, 2017 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on November 27, 2017)
10.2+	Employee Matters Agreement, dated as of June 14, 2010, by and between Questar Corporation and QEP Resources, Inc. (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on June 16, 2010)
10.3+	Amended and Restated QEP Resources, Inc. Deferred Compensation Wrap Plan, dated May 15, 2017 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q, filed by the Company with the Securities and Exchange Commission on July 26, 2017)
10.4+	Amended and Restated QEP Resources, Inc. Deferred Compensation Plan for Directors, dated July 24, 2017 (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q, filed by the Company with the Securities and Exchange Commission on July 26, 2017)
10.5+	Cash Incentive Plan, dated effective as of January 1, 2012 (incorporated by reference to Appendix A to the Company's Proxy Statement on Schedule 14A, filed with the Securities and Exchange Commission on April 3, 2012), as amended by Amendment Number One to Cash Incentive Plan, effective as of October 26, 2015 (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8‑K, filed with the Securities and Exchange Commission on October 29, 2015)
10.6+	2010 Long-Term Stock Incentive Plan, adopted June 12, 2010 (incorporated by reference to Exhibit 10.9 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on June 16, 2010), as amended by Amendment Number One to Long-Term Stock Incentive Plan, effective as of October 26, 2015 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on October 29, 2015)
10.7+	Executive Severance Compensation Plan - CIC, as Amended and Restated Effective as of October 26, 2015 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on October 29, 2015)

128

10.8+	Form of Indemnification Agreement for directors and officers (incorporated by reference to Exhibit 10.8 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on November 5, 2013)
10.9+	Supplemental Executive Retirement Plan, effective as of January 1, 2016 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on August 3, 2015)
10.10+	Form of Nonqualified Stock Option Agreement for nonqualified stock options granted to the CEO and CFO in 2011, 2012 and 2013 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on June 29, 2010)
10.11+	Form of Nonqualified Stock Option Agreement for nonqualified stock options granted to executive officers other than the CEO and CFO in 2011, 2012 and 2013 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on June 29, 2010)
10.12+	Form of Nonqualified Stock Option Agreement for nonqualified stock options granted to executive officers in 2014 and 2015 (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on January 23, 2014)
10.13+	Form of Nonqualified Stock Option Agreement for nonqualified stock options granted to executive officers in 2016 and 2017 (incorporated by reference to Exhibit 10.4, to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on October 29, 2015)
10.14+	Form of Amendment to Certain Stock Option Agreements under the QEP Resources, Inc 2010 Long-Term Stock Incentive Plan adopted January 20, 2014 (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on January 23, 2014)
10.15+	Form of Restricted Stock Agreement for restricted stock granted to executive officers in 2015 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on January 23, 2014)
10.16+	Form of Restricted Stock Agreement for restricted stock granted to executive officers in 2016 and 2017 (incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on October 29, 2015)
10.17*+	Form of Restricted Stock Agreement for restricted stock granted to executive officers in 2018
10.18+	Form of Restricted Stock Agreement for restricted stock granted to non-employee directors (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on October 29, 2015)
10.19+	Form of Phantom Stock Agreement for phantom stock granted to non-employee directors (incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on June 29, 2010)
10.20+	Form of Performance Share Unit Award Agreement for performance share units granted to executive officers in 2015 (incorporated by reference to Exhibit 10.42 to the Company's Annual Report on Form 10-K, filed with the Securities and Exchange Commission on February 24, 2015)
10.21+	Form of Performance Share Unit Award Agreement for performance share units granted to executive officers in 2016 (incorporated by reference to Exhibit 10.7 to the Company's Annual Report on Form 8-K, filed with the Securities and Exchange Commission on October 29, 2015)
10.22+	Form of Performance Share Unit Award Agreement for performance share units granted to executive officers in 2017 (incorporated by reference to Exhibit 10.33 to the Company's Annual Report on Form 10-K, filed with the Securities and Exchange Commission on February 22, 2017)
10.23*+	Form of Performance Share Unit Award Agreement for performance share units granted to executive officers in 2018
10.24	Purchase and Sale Agreement, dated June 21, 2016, by and among QEP Energy Company, as purchaser, and RK Petroleum Corp. and various other owners of certain oil and gas properties in the Permian Basin, as sellers (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on July 27, 2016), as amended by the First Amendment to Purchase and Sale Agreement, dated as of September 7, 2016 (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on October 26, 2016), and the Second Amendment to Purchase and Sale Agreement, dated September 14, 2016 (incorporated by reference to Exhibit 1.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on September 19, 2016)
10.25	Purchase and Sale Agreement, dated July 26, 2017, by and between QEP Energy Company, as buyer, and JM Cox Resources, L.P., Alpine Oil Company, and Kelly Cox, collectively as sellers (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company with the Securities and Exchange Commission on July 26, 2017)

129

10.26	Purchase and Sale Agreement, dated July 24, 2017, by and between QEP Energy Company, as seller, and Pinedale Energy Partners, LLC, as buyer (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed by the Company with the Securities and Exchange Commission on July 25, 2017)
10.27+	Separation Agreement, dated as of September 15, 2017, between the Company and Matthew T. Thompson (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q, filed by the Company with the Securities and Exchange Commission on October 25, 2017)
10.28+	Amendment to Long Term Incentive Agreements, dated as of September 15, 2017, between the Company and Matthew T. Thompson (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10‑Q, filed by the Company with the Securities and Exchange Commission on October 25, 2017)
10.29*+	Form of Retention Bonus Letter Agreement, dated February 26, 2018, between the Company and each of its executive officers
10.30*+	Form of Severance Compensation Program Letter Agreement, dated February 26, 2018, between the Company and each of its executive officers
10.31*	Letter Agreement, dated February 28, 2018, by and between QEP Resources, Inc. and Elliott Management Corporation
12.1*	Ratio of earnings to fixed charges
21.1*	Subsidiaries of the Company
23.1*	Consent of Independent Registered Public Accounting Firm – PricewaterhouseCoopers LLP
23.2*	Consent of Independent Petroleum Engineers and Geologists – Ryder Scott Company, L.P.
23.3*	Consent of Independent Petroleum Engineers and Geologists – DeGolyer and MacNaughton
24*	Power of Attorney
31.1*	Certification signed by Charles B. Stanley, QEP Resources, Inc., Chairman, President and Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification signed by Richard J. Doleshek, QEP Resources, Inc. Executive Vice President, Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification signed by Charles B. Stanley and Richard J. Doleshek, QEP Resources, Inc. Chairman, President and Chief Executive Officer and Executive Vice President, Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1*	Qualifications and Report of Independent Petroleum Engineers and Geologists – Ryder Scott Company, L.P.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Schema Document
101.CAL**	XBRL Calculation Linkbase Document
101.LAB**	XBRL Label Linkbase Document
101.PRE**	XBRL Presentation Linkbase Document
101.DEF**	XBRL Definition Linkbase Document

____________________________

* Filed herewith

** These interactive data files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.

+ Indicates a management contract or compensatory plan or arrangement

130

(c) Financial Statements Schedules:  All schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.

131

ITEM 16. FORM 10-K SUMMARY

None.

132

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 28, 2018.

QEP RESOURCES, INC.

(Registrant)

/s/ Charles B. Stanley

Charles B. Stanley,

Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 28, 2018.

/s/ Charles B. Stanley		Chairman, President and Chief Executive Officer
Charles B. Stanley		(Principal Executive Officer)
/s/ Richard J. Doleshek		Executive Vice President and Chief Financial Officer
Richard J. Doleshek		(Principal Financial Officer)
/s/ Alice B. Ley		Vice President, Controller and Chief Accounting Officer
Alice B. Ley		(Principal Accounting Officer)
*Charles B. Stanley		Chairman of the Board; Director
*David Trice		Director
*Julie A. Dill		Director
*M. W. Scoggins		Director
*Mary Shafer Malicki		Director
*Michael J. Minarovic		Director
*Phillips S. Baker, Jr.		Director
*Robert F. Heinemann		Director
*William L. Thacker III		Director
February 28, 2018	*By	/s/ Charles B. Stanley
		Charles B. Stanley, Attorney in Fact

133

EX-10.17

Exhibit 10.17

QEP RESOURCES INC.

2010 LONG-TERM STOCK INCENTIVE PLAN

RESTRICTED STOCK AGREEMENT

THIS RESTRICTED STOCK AGREEMENT (the "Agreement") is made as of [grant date] (the "Effective Date"), between QEP Resources, Inc., a Delaware corporation (the "Company"), and [participant name] ("Grantee").

1.    Grant of Restricted Stock. Subject to the terms and conditions of this Agreement and the QEP Resources, Inc. 2010 Long-Term Stock Incentive Plan, as may be amended from time to time (the "Plan"), for good and valuable consideration, on the Effective Date, the Company hereby issues to Grantee [shares granted] shares of the Company’s Common Stock, $.01 par value, subject to certain restrictions thereon (the "Restricted Stock").

2.    Restrictions. Shares of Restricted Stock may not be sold, assigned, transferred by gift or otherwise, pledged, hypothecated, or otherwise disposed of, by operation of law or otherwise, and shall be subject to forfeiture in accordance with the provisions of Section 5, below, until Grantee becomes vested in the Restricted Stock. Upon vesting, the restrictions in this Section 2 shall lapse, the Restricted Stock shall no longer be subject to forfeiture, and Grantee may transfer shares of Restricted Stock in accordance with the Securities Act of 1933 and other applicable securities laws.

3.    Enforcement of Restrictions. To enforce the restrictions set forth in Section 2, shares of Restricted Stock will be held in electronic form in an account by the Company’s transfer agent or other designee until the restrictions set forth in Section 2 have lapsed with respect to such shares, or such shares are forfeited, whichever is earlier.

4.    Vesting; Lapse of Restrictions. Except as provided otherwise in this Agreement, the Restricted Stock shall vest in three equal increments on an annual basis in March or September (depending on grant date) beginning no sooner than eight months after grant date and no later than fourteen months after grant date, subject to Grantee’s continued Service as an Employee from the Effective Date until the vesting dates (each, a "Vesting Date").

The number of shares of Restricted Stock that are vested shall be cumulative, so that once a share becomes vested, it shall continue to be vested.

If the Vesting Date falls on a day when the New York Stock Exchange (NYSE) is closed, the Vesting Date will occur on the next day that the NYSE is open. In the event that the Vesting Date falls on a day when trading in the Common Stock has been suspended, the Vesting Date will occur on the next full day after trading resumes.

5.    Termination of Employment; Forfeiture of Restricted Stock. If Grantee’s employment with the Company terminates, shares of Restricted Stock shall be treated as follows unless Grantee is subject to an employment agreement or other agreement that governs treatment of Restricted Stock upon termination, in which case the terms of the other agreement shall govern.

(a)    Death or Disability. If Grantee’s employment with the Employer is terminated due to Grantee’s death or Disability prior to any Vesting Date, any unvested shares of Restricted Stock shall vest in full and the restrictions set forth in Section 2 shall lapse in their entirety.

(b)    Termination Following a Change in Control. If, upon a Change in Control of the Company or within the three years thereafter, Grantee’s employment with the Employer is terminated (i) by Grantee’s Employer for any reason other than Cause or (ii) by Grantee for Good Reason within 60 days following the expiration of the cure period afforded to the Company to rectify the condition giving rise to Good Reason, any unvested shares of the Restricted Stock shall vest in full and the restrictions set forth in Section 2 shall lapse in their entirety. For purposes of this Section 5(b):

1

(i)    "Cause" means Grantee’s:  (i) willful and continued failure to perform substantially Grantee’s duties with the Employer (other than any such failure resulting from incapacity due to physical or mental illness), following written demand for substantial performance delivered to Grantee by the Board or the Chief Executive Officer of the Company; or (ii) willful engagement in conduct that is materially injurious to the Employer. For purposes of this definition, no act or failure to act on the part of Grantee shall be considered "willful" unless it is done, or omitted to be done, by Grantee without reasonable belief that Grantee’s action or omission was in the best interests of Grantee’s Employer. The Company, acting through the Board, must notify Grantee in writing that Grantee’s employment is being terminated for "Cause". The notice shall include a list of the factual findings used to sustain the judgment that Grantee’s employment is being terminated for "Cause".

(ii)    "Good Reason" means any of the following events or conditions that occur without Grantee’s written consent, and that remain in effect after notice has been provided by Grantee to the Company of such event or condition and the expiration of a 30 day cure period:  (i) a material diminution in Grantee’s gross annual base salary (as in effect immediately prior to the Change in Control of the Company), target incentive opportunity under any Annual Cash Incentive Plan or long-term incentive award opportunity under any Long-Term Incentive Plan or Stock Incentive Plan; (ii) a material diminution in Grantee’s authority, duties, or responsibilities; (iii) a material diminution in the authority, duties, or responsibilities of the supervisor to whom Grantee is required to report, including a requirement that Grantee report to a corporate officer or employee instead of reporting directly to the Board; (iv) a material diminution in the budget over which Grantee retains authority; (v) a material change in the geographic location at which Grantee performs services; or (vi) any other action or inaction that constitutes a material breach by the Employer of Grantee’s employment agreement (if any). Grantee’s notification to the Company must be in writing and must occur within a reasonable period of time, not to exceed 90 days, following the initial existence of the relevant event or condition. For purposes of this definition:

(1) "Annual Cash Incentive Plan" means any annual incentive plan, program or arrangement offered by the Employer pursuant to which Grantee is eligible to receive a cash award, subject in whole or in part to the achievement of performance goals over a period of no more than one year, including without limitation the QEP Resources, Inc. Cash Incentive Plan.

(2) "Long-Term Incentive Plan" means any long-term incentive plan, program or arrangement offered by the Employer pursuant to which Grantee is eligible to receive an award, subject in whole or in part to the achievement of performance goals over a period of more than one year, including without limitation the QEP Resources, Inc. Cash Incentive Plan.

(3) "Stock Incentive Plan" means any incentive plan offered by the Company pursuant to which upon or following vesting or exercise, as applicable, Grantee is entitled to receive shares of the Company’s Common Stock, including without limitation the Plan.

(c)    Other Terminations of Employment. Except as provided in Section 5(a) and Section 5(b) above, if Grantee’s employment with the Employer is terminated for any reason prior to any Vesting Date, Grantee shall forfeit all shares of Restricted Stock that are not yet vested at the time of such termination.

(d)    Manner of Forfeiture. Any shares of Restricted Stock forfeited by Grantee pursuant to this Section 5 shall promptly be transferred to the Company without the payment of any consideration therefor, and Grantee or Grantee’s attorney-in-fact, shall execute all documents and take all actions as shall be necessary or desirable to promptly effectuate such transfer. On and after the time at which any shares are required to be transferred to the Company, the Company shall not pay any dividend to Grantee on account of such shares or permit Grantee to exercise any of the privileges or rights of a stockholder with respect to the shares but shall, in so far as permitted by law, treat the Company as owner of the shares.

6.    Effect of Prohibited Transfer. If any transfer of Restricted Stock is made or attempted to be made contrary to the terms of this Agreement, the Company shall have the right to acquire for its own account, without the payment of any consideration therefor, such shares from the owner thereof or his or her transferee, at any time before or after such prohibited transfer. In addition to any other legal or equitable remedies it may have, the Company may enforce its rights to specific performance to the extent permitted by law and may exercise such other equitable remedies then available to it. The Company may refuse for any purpose to recognize any transferee who receives shares contrary to the provisions of this Agreement as a stockholder of the Company and may retain and/or recover all dividends on such shares that were paid or payable subsequent to the date on which the prohibited transfer was made or attempted.

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7.    Rights of a Stockholder. Subject to the restrictions imposed by Section 2 and the terms of any other relevant sections hereof, Grantee shall have all of the voting, dividend, liquidation and other rights of a stockholder with respect to the Restricted Stock.

8.    Adjustments to Restricted Stock.

(a)    Adjustment by Merger, Stock Split, Stock Dividend, Etc. If the Common Stock, as presently constituted, shall be changed into or exchanged for a different number or kind of shares of stock or other securities of the Company or of another corporation (whether by reason of merger, consolidation, recapitalization, reclassification, stock split, spinoff, combination of shares or otherwise), or if the number of such shares of stock shall be increased through the payment of a stock dividend, then there shall be substituted for or added to each share of Restricted Stock, the number and kind of shares of stock or other securities into which each outstanding share of Restricted Stock shall be so changed or for which each such share shall be exchanged or to which each such share shall be entitled, as the case may be.

(b)    Other Distributions and Changes in the Stock.In the event there shall be any other change affecting the number or kind of the outstanding shares of the Common Stock, or any stock or other securities into which the stock shall have been changed or for which it shall have been exchanged, then if the Committee shall, in its sole discretion, determine that the change equitably requires an adjustment in the shares of Restricted Stock, an adjustment shall be made in accordance with such determination.

(c)    General Adjustment Rules. All adjustments relating to stock or securities of the Company shall be made by the Committee, whose determination in that respect shall be final, binding and conclusive. Fractional shares resulting from any adjustment to the Restricted Stock pursuant to this Section 8 may be settled as the Committee shall determine. Notice of any adjustment shall be given to Grantee.

(d)    Reservation of Rights. The issuance of Restricted Stock shall not affect in any way the right or power of the Company to make adjustments, reclassifications, reorganizations or changes of its capital or business structure, to merge, to consolidate, to dissolve, to liquidate or to sell or transfer all or any part of its business or assets.

9.    Tax Consequences. Set forth below is a brief summary as of the date of grant of certain United States federal income tax consequences of the award of the Restricted Stock. THIS SUMMARY DOES NOT ADDRESS EMPLOYMENT, SPECIFIC STATE, LOCAL OR FOREIGN TAX CONSEQUENCES THAT MAY BE APPLICABLE TO GRANTEE. GRANTEE UNDERSTANDS THAT THIS SUMMARY IS NECESSARILY INCOMPLETE, AND THE TAX LAWS AND REGULATIONS ARE SUBJECT TO CHANGE.

Unless Grantee makes a Section 83(b) election as described below, Grantee shall recognize ordinary income at the time or times the shares of Restricted Stock are released from the restrictions in Section 2, in an amount equal to the Fair Market Value of the shares on such date(s) less the amount paid, if any, for such shares, and the Company shall collect all applicable withholding taxes with respect to such income.

10.    Tax Withholding Obligations.

(a)    Upon taxation of the Restricted Stock, Grantee shall make appropriate arrangements with the Company to provide for the payment of all applicable tax withholdings. Grantee may elect to satisfy such withholding liability by:

(i)    Payment to the Company in cash;

(ii)    Deduction from Grantee’s regular pay;

(iii)    Withholding of a number of shares of vested Restricted Stock having an aggregate Fair Market Value equal to the minimum amount required to be withheld or such greater amount, up to the maximum allowable, as may be elected by Grantee; or

(iv)    Transfer to the Company of a number of shares of Common Stock that were acquired by Grantee more than six (6) months prior to the transfer to the Company, with such shares having an aggregate Fair Market Value equal to the amount required to be withheld or such lesser or greater amount as may be elected by Grantee, up to Grantee’s marginal tax payment obligations associated with the taxation of the Restricted Stock.

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    (b)    All elections under this Section 10 shall be subject to the approval or disapproval of the Committee. Unless the Committee determines otherwise or Grantee has notified the Company in writing otherwise, Grantee shall be deemed to have elected the method described in Section 10(a)(iii). The value of shares withheld or transferred shall be based on the Fair Market Value of the stock on the date that the amount of tax to be withheld is to be determined (the "Tax Date").

(c)    All elections under this Section 10 shall be subject to the following restrictions:

(i)    All elections must be made prior to the Tax Date;

(ii)    All elections shall be irrevocable; and

(iii)    If Grantee is an officer or director of the Company within the meaning of Section 16 of the 1934 Act ("Section 16"), Grantee must satisfy the requirements of such Section 16 and any applicable rules thereunder with respect to the use of stock to satisfy such tax withholding obligation.

11.    Section 83(b) Election. Grantee hereby acknowledges that he or she has been informed that he or she may file with the Internal Revenue Service, within thirty (30) days of the Effective Date, an election pursuant to Section 83(b) of the Internal Revenue Code of 1986, as amended, to be taxed as of the Effective Date on the amount by which the Fair Market Value of the Restricted Stock as of such date exceeds the price paid for such shares, if any.

IF GRANTEE CHOOSES TO FILE AN ELECTION UNDER SECTION 83(b) OF THE CODE, GRANTEE ACKNOWLEDGES THAT IT IS GRANTEE’S SOLE RESPONSIBILITY AND NOT THE COMPANY’S TO FILE TIMELY THE ELECTION UNDER SECTION 83(b) OF THE CODE, EVEN IF GRANTEE REQUESTS THE COMPANY OR ITS REPRESENTATIVE TO MAKE THIS FILING ON GRANTEE’S BEHALF.

BY SIGNING THIS AGREEMENT, GRANTEE REPRESENTS THAT HE OR SHE HAS REVIEWED WITH HIS OR HER OWN TAX ADVISORS THE FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES OF THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT AND THAT HE OR SHE IS RELYING SOLELY ON SUCH ADVISORS AND NOT ON ANY STATEMENTS OR REPRESENTATIONS OF THE COMPANY OR ANY OF ITS AGENTS. GRANTEE UNDERSTANDS AND AGREES THAT HE OR SHE (AND NOT THE COMPANY) SHALL BE RESPONSIBLE FOR ANY TAX LIABILITY THAT MAY ARISE AS A RESULT OF THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT.

12.    Notices. Any notice required or permitted to be given under this Agreement shall be in writing and shall be given by hand delivery or by first class registered or certified mail, postage prepaid, addressed, if to the Company, to its Corporate Secretary, and if to Grantee, to his or her address now on file with the Company, or to such other address as either may designate in writing. Any notice shall be deemed to be duly given as of the date delivered in the case of personal delivery, or as of the second day after enclosed in a properly sealed envelope and deposited, postage prepaid, in a United States post office, in the case of mailed notice.

13.    Amendment. Except as provided herein, this Agreement may not be amended or otherwise modified unless evidenced in writing and signed by the Company and Grantee, and as approved by the Committee or its delegate. Notwithstanding any provision in this Agreement to the contrary, including Section 14, an amendment to the Plan that would materially and adversely affect Grantee’s rights with respect to the award of Restricted Stock granted hereunder will not be effective with respect to such award.

14.    Relationship to Plan. This Agreement shall not alter the terms of the Plan. If there is a conflict between the terms of the Plan and the terms of this Agreement, the terms of the Plan shall prevail. Capitalized terms used in this Agreement but not defined herein shall have the meaning given such terms in the Plan.

15.    Construction; Severability. The section headings contained herein are for reference purposes only and shall not in any way affect the meaning or interpretation of this Agreement. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, and each other provision of this Agreement shall be severable and enforceable to the extent permitted by law.

16.    Waiver. Any provision contained in this Agreement may be waived, either generally or in any particular instance, by the Committee appointed under the Plan, but only to the extent permitted under the Plan.

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17.    Entire Agreement; Binding Effect. Once accepted, this Agreement, the terms and conditions of the Plan, and the award of Restricted Stock set forth herein, constitute the entire agreement between Grantee and the Company governing such award of Restricted Stock, and shall be binding upon and inure to the benefit of the Company and to Grantee and to the Company’s and Grantee’s respective heirs, executors, administrators, legal representatives, successors and assigns.

18.    No Rights to Employment. Nothing contained in this Agreement shall be construed as giving Grantee any right to be retained in the employ of your Employer and this Agreement is limited solely to governing the rights and obligations of Grantee with respect to the Restricted Stock.

19.    Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware, without regard to the choice of law principles thereof.

IN WITNESS WHEREOF, the parties have executed this Agreement as of [acceptance date].

GRANTEE	QEP RESOURCES, INC.
[Electronic signature]	/s/ Richard J. Doleshek
[Name]	Richard J. Doleshek
	Executive Vice President and Chief Financial Officer

5

EX-10.23

Exhibit 10.23

QEP RESOURCES, INC.

CASH INCENTIVE PLAN

PERFORMANCE SHARE UNIT AWARD AGREEMENT

THIS PERFORMANCE SHARE UNIT AWARD AGREEMENT (the "Agreement") is made as of _______________ (the "Effective Date"), between QEP Resources, Inc., a Delaware corporation (the "Company"), and ______________ (the "Grantee").

1. Grant of Performance Share Units. Subject to the terms and conditions of this Agreement and the Company’s Cash Incentive Plan (the "Plan"), the Company hereby issues to Grantee the right to receive a number of Performance Share Units calculated in the manner set forth in Appendix A hereto, based on the achievement of one or more Performance Goals that must be attained over a relevant Performance Period, and assuming a target award of ______________ Performance Share Units (the "Target Share Units"). Each Performance Share Unit actually earned and vested in accordance with this Agreement and Appendix A hereto represents the right to receive a cash payment equal to the Fair Market Value of one share of the Company’s no par value common stock ("Common Stock"), subject to Section 3 and the other terms and conditions of this Agreement. Terms not defined herein shall have the meanings ascribed to them in the Plan.

2. Vesting; Termination of Employment; Forfeiture.

General. Except as set forth below, the Grantee will vest and become entitled to any Performance Share Units earned in accordance with this Agreement and Appendix A hereto only if the Grantee remains in the continuous employment of the Company and its Affiliates from the Effective Date through the date such earned Performance Share Units are paid in accordance with Section 3 (the "Vest Date").

a) Termination of Employment. Except as provided in subsections (b) and (c) below, if the Grantee terminates employment with the Company and its Affiliates for any reason prior to the Vest Date, the Grantee shall forfeit any and all interest under this Agreement and shall forfeit the right to receive any Performance Share Units hereunder.

b) Death, Disability, or Retirement. If the Grantee terminates employment with the Company and its Affiliates on account of death, Disability, or Retirement (as defined below) prior to the last day of the Performance Period, the Grantee shall receive on the Vest Date a pro rata portion of the Performance Share Units that would otherwise have been received for the Performance Period, subject to certification by the Committee, in an amount equal to the product of (x) the number of Performance Share Units that would have been earned in accordance with the provisions of Appendix A had Grantee remained in the continuous employment of the Company or its Affiliates through the last day of the Performance Period, multiplied by (y) the ratio between (i) the number of full months of employment

completed from the first day of the Performance Period to the date of termination of employment and (ii) the number of full months in the Performance Period. If the Grantee terminates employment with the Company and its Affiliates on account of death, Disability, or Retirement on or after the last day of the Performance Period but before the Vest Date, the Grantee shall receive on the Vest Date the Performance Share Units that would have been earned in accordance with the provisions of Appendix A had the Grantee remained in the continuous employment of the Company or its Affiliates through the Vest Date. "Retirement" shall mean Grantee’s voluntary termination of employment with the Company and its Affiliates on or after age 55 with at least 10 years of service; provided that such retirement occurs no earlier than 12 months after the first day of the Performance Period, or such other retirement as shall be approved by the Committee in its discretion.

c) Termination Following a Change in Control. If, upon a Change in Control of the Company or within the three years thereafter, the Grantee’s employment is terminated prior to the Vest Date (i) by the Company and its Affiliates for any reason other than Cause (as defined below) or Disability (it being understood that upon termination for Disability, the provisions of paragraph (b) above shall apply) or (ii) by the Grantee for Good Reason (as defined below) within 60 days following the expiration of the cure period afforded the Company to rectify the condition giving rise to Good Reason, the Grantee shall be entitled to receive a payment for the Performance Share Units earned hereunder based on the greater of (A) the level of achievement of the applicable performance goals as of immediately prior to the Change in Control or (B) the level of achievement of the applicable performance goals as of the date of termination of employment (which for administrative convenience may be determined as of the most recently completed calendar quarter). Such payment will be made to the Grantee within 30 days after the Grantee’s termination of employment. For purposes of this subsection (c):

i. "Cause" means the Grantee’s:  (i) willful and continued failure to perform substantially the Grantee’s duties with an Employer (other than any such failure resulting from incapacity due to physical or mental illness), following written demand for substantial performance delivered to the Grantee by the Board or the Chief Executive Officer of the Company; or (ii) willful engagement in conduct that is materially injurious to an Employer. For purposes of this definition, no act or failure to act on the part of the Grantee shall be considered "willful" unless it is done, or omitted to be done, by the Grantee without reasonable belief that the Grantee’s action or omission was in the best interests of the Grantee’s Employer. The Company, acting through the Board, must notify the Grantee in writing that the Grantee’s employment is being terminated for "Cause". The notice shall include a list of the factual findings used to sustain the judgment that the Grantee’s employment is being terminated for "Cause".

ii. "Good Reason" means any of the following events or conditions that occur without the Grantee’s written consent, and that remain in effect after notice has been provided by the Grantee to the Company of such event or condition and the expiration of a 30 day cure period:  (i) a material diminution in the Grantee’s gross annual base salary (as in effect immediately prior to the Change in Control of the Company), target incentive opportunity under any Annual Cash Incentive Plan or long-term incentive award opportunity under any Long-Term Incentive Plan or Stock Incentive Plan; (ii) a material diminution in the Grantee’s authority, duties, or responsibilities; (iii) a material diminution in the authority, duties, or responsibilities of the supervisor to whom the Grantee is required to report, including a requirement that the Grantee report to a corporate officer or employee instead of reporting directly to the Board; (iv) a material diminution in the budget over which the Grantee retains authority; (v) a material change in the geographic location at which the Grantee performs services; or (vi) any other action or inaction that constitutes a material breach by an Employer of the Grantee’s employment agreement (if any). The Grantee’s notification to the Company must be in writing and must occur within a reasonable period of time, not to exceed 90 days, following the initial existence of the relevant event or condition. For purposes of this definition:

A. "Annual Cash Incentive Plan" means any annual incentive plan, program or arrangement offered by an Employer pursuant to which the Grantee is eligible to receive a cash award, subject in whole or in part to the achievement of performance goals over a period of no more than one year, including without limitation the Plan.

B. "Long-Term Incentive Plan" means any long-term incentive plan, program or arrangement offered by an Employer pursuant to which the Grantee is eligible to receive an award, subject in whole or in part to the achievement of performance goals over a period of more than one year, including without limitation the Plan.

C. "Stock Incentive Plan" means any incentive plan offered by the Company pursuant to which upon or following vesting or exercise, as applicable, the Grantee is entitled to receive shares of the Company’s Common Stock, including without limitation the QEP Resources, Inc. 2010 Long-Term Stock Incentive Plan.

3. Payment.

a) General. As soon as practicable after the end of the Performance Period the Committee shall determine and certify the number of Performance Share Units that have been earned in accordance with Appendix A and the terms and conditions of this Agreement. Subject to

subsection (b), payment for Performance Share Units shall be made in cash on the Vest Date. The amount distributable shall be based on the average closing Company stock price for the fourth quarter of the final year of the Performance Period. All payments shall be made as soon as administratively practicable after the date on which the Committee determines and certifies the number of Performance Share Units that have been earned, but in all events not later than March 15 of the calendar year following the calendar year in which the Performance Period ends. The foregoing provisions are subject to the terms of any valid and effective deferral election made by the Grantee with respect to the Performance Share Units under the QEP Resources, Inc. Deferred Compensation Wrap Plan.

b) Payment in Shares. Notwithstanding anything in the Plan, this Agreement or in Appendix A to the contrary, in lieu of paying the Performance Share Units in cash as provided in subsection (a), the Committee may elect in its discretion to pay some or all of the Performance Share Units in the form of an equal number of actual shares of the Company’s (or its successor’s) Common Stock or other applicable securities, which shares of Common Stock or other applicable securities shall be delivered to the Grantee under the Company’s 2010 Long-Term Stock Incentive Plan (as it may be amended or restated from time to time, or, to the extent applicable, any future or successor equity compensation plan of the Company).

4. No Rights of a Stockholder. The Grantee shall have no voting or other rights as a stockholder of the Company with respect to this award. The Grantee’s right to receive payments earned under this Agreement shall be no greater than the right of any unsecured general creditor of the Company.

5. Adjustments to Performance Share Units. In the event of any stock dividend, extraordinary cash dividend, recapitalization, reorganization, merger, consolidation, split-up, spin-off, combination, exchange of shares, grant of warrants or rights offering to purchase Common Stock at a price materially below fair market value or other similar corporate event affecting the Common Stock, the Committee shall adjust the award issued hereunder in order to preserve the benefits or potential benefits intended to be made available under this Agreement. All adjustments shall be made in the sole and exclusive discretion of the Committee, whose determination shall be final, binding and conclusive. Notice of any adjustment shall be given to Grantee.

6. Notices. Any notice required or permitted to be given under this Agreement shall be in writing and shall be given by e-mail, hand delivery or by first class registered or certified mail, postage prepaid, addressed, if to the Company, to its Corporate Secretary, and if to Grantee, to his or her address now on file with the Company, or to such other address as either may designate in writing. Any notice shall be deemed to be duly given as of the date delivered in the case of e-mail or personal delivery, or as of the second day after enclosed in a properly sealed envelope and deposited, postage prepaid, in a United States post office, in the case of mailed notice.

7. Amendment. Except as provided herein, this Agreement may not be amended or otherwise modified unless evidenced in writing and signed by the Company and Grantee, or as approved by the Committee or its delegate. Notwithstanding any provision in this Agreement to the contrary, including Section 8, an amendment to the Plan that would materially and adversely affect Grantee’s rights with respect to the award of Performance Share Units granted hereunder will not be effective with respect to such award.

8. Relationship to Plan. Except to the extent this Agreement provides for the discretionary stock settlement of the Target Share Units, this Agreement shall not alter the terms of the Plan. If there is a conflict between the terms of the Plan and the terms of this Agreement, the terms of the Plan shall prevail, provided, however, that the terms of Section 3(b) of this Agreement shall control over any contrary provision of the Plan. Capitalized terms used in this Agreement but not defined herein shall have the meaning given such terms in the Plan.

9. Construction; Severability. The section headings contained herein are for reference purposes only and shall not in any way affect the meaning or interpretation of this Agreement. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, and each other provision of this Agreement shall be severable and enforceable to the extent permitted by law.

10. Waiver. Any provision contained in this Agreement may be waived, either generally or in any particular instance, by the Committee appointed under the Plan, but only to the extent permitted under the Plan.

11. Entire Agreement; Binding Effect. Once accepted, this Agreement, the terms and conditions of the Plan, and the award of Performance Share Units set forth herein, constitute the entire agreement between Grantee and the Company governing such award of Performance Share Units, and shall be binding upon and inure to the benefit of the Company and to Grantee and to the Company’s and Grantee’s respective heirs, executors, administrators, legal representatives, successors and assigns.

12. No Rights to Employment. Nothing contained in this Agreement shall be construed as giving Grantee any right to be retained in the employ of the Company or its Affiliates and this Agreement is limited solely to governing the rights and obligations of Grantee with respect to the Performance Share Units.

13. Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware, without regard to the choice of law principles thereof.

14. Section 409A. For the avoidance of doubt, the provisions of Section 7(g) of the Plan shall apply to this Agreement and all payments made or to be made in connection with this Agreement.

IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first above written.

GRANTEE		QEP RESOURCES, INC.
[Electronic signature]		/s/ Richard J. Doleshek
[Name]	By:	Richard J. Doleshek
		Executive Vice President and Chief Financial Officer

APPENDIX A

TO THE PERFORMANCE SHARE UNIT AWARD AGREEMENT

Determination of Target Share Units

The dollar value of the award, as determined by the Committee, is denominated in Target Share Units based on the closing price of Company Common Stock on the date of the award (March 1, 2018).

Performance Period

The Performance Period is January 1, 2018 through December 31, 2020.

Performance Goals

The performance measure for the award is the Company’s total shareholder return (TSR) compared to the TSR of a group of peer companies. TSR combines share price appreciation and dividends paid to show the total return to the shareholder. Although TSR will vary with the stock market, the relative position to Company’s peers over a 3-year period is the performance metric in this Plan.

TSR, expressed as a percentage, will be (i) the Company’s ending stock price plus dividends over the three-year period minus the Company’s beginning stock price, divided by (ii) the Company’s beginning stock price. For both the beginning and ending stock prices, the calculation uses the average closing price during the previous quarter (i.e., beginning price is the average during Q4 2017 and the ending price is the average during Q4 2020). This calculation is used instead of the actual closing price on the given date to smooth volatility in the stock price and avoid single-day fluctuations.

TSR Percentage =	ending stock price + dividends paid in Perf. Period - beginning stock price
	beginning stock price

Peer Group

The following companies are included in the Company’s peer group:

Callon Petroleum Co/DE	Matador Resources Co
Carrizo Oil & Gas Inc	Newfield Exploration Co
Centennial Resource Development Inc	Oasis Petroleum Inc
Cimarex Energy Co	Parsley Energy Inc
Diamondback Energy Inc	PDC Energy Inc
Energen Corp	Range Resources Inc
EP Energy Corp	RSP Permian Inc
Extraction Oil & Gas Inc	SM Energy Co
Gulfport Energy Corp	Southwestern Energy Co
Jagged Peak Energy Inc	Whiting Petroleum Corp
Laredo Petroleum Inc	WPX Energy Inc

Should a peer company file a bankruptcy or similar petition or otherwise seek any protection from creditors under an available legal process or cease to exist as a separate publicly-traded company during the Performance Period (e.g., due to acquisitions, etc.), it will nonetheless remain as a member of the Company’s peer group for purposes of the Payout Calculation described below and the Company shall be ranked higher than such peer company for purposes of the Payout Calculation.

Performance and Payout Calculations

At the end of the Performance Period, the number of Target Share Units will be adjusted based on the Company’s TSR relative to the Company’s peer group over the three-year period. The Company’s TSR is ranked among the TSR of all peer companies and the percentile rank is calculated based on the Company’s position in the ranking (e.g. if the Company’s TSR ranks 13^th out of 25 companies, the Company is at the 50^th percentile). The performance scale is detailed in the following table, with interpolation between the 30^th and 90^th Percentile Ranks.

Company’s Percentile Rank in Peer Group	Shares Earned as Percent of Target (Performance %)
90th Percentile or Above	200%
70th Percentile	150%
50th Percentile	100%
30th Percentile	50%
Below 30th Percentile	0%

Notwithstanding the foregoing, in the event the Company’s TSR is between negative 25% and 0% on an absolute cumulative basis over the Performance Period, then the Performance Percentage for this performance measure will not be more than 150%, and in the event the Company’s TSR is less than negative 25% on an absolute cumulative basis over the Performance Period, then the Performance Percentage for this performance measure will not be more than 100% (i.e., the Performance Percentage for this performance measure is capped at 150% if the Company’s shareholders experience a negative return over the Performance Period and it is capped at 100% if the total negative return over the Performance Period is worse than negative 25%). In addition, notwithstanding the foregoing, if QEP’s average annualized TSR over the Performance Period is equal to or greater than 15% (assuming annual compounding), then the Performance Percentage for this performance measure will not be less than 50% (i.e., there is a 50% floor on the Performance Percentage if the Company’s shareholders earn at least a 15% annualized return over the Performance Period).

If the earned Target Share Units are being paid in cash, the Target Share Units will be converted into cash based on the average closing Company stock price for the fourth quarter of 2020. The actual payout under the Plan at the end of the Performance Period, as set forth in Section 3, is calculated using the following formula, which assumes 100% cash settlement of earned awards:

Payout = (number of Target Share Units awarded) x (performance percentage) x (average closing Company stock price in the fourth quarter of the final year of the Performance Period)

EX-10.29

Exhibit 10.29

February 26, 2018

[NAME]

Re: Executive Retention Bonus

Dear [NAME]:

This "Retention Bonus Letter" confirms the agreement between you (the "Participant") and QEP Resources, Inc. (the "Company") regarding a retention bonus award opportunity that is being offered to you. This Retention Bonus Letter offers you a supplemental benefit that is in addition to the Severance Benefits (as defined in the Participation Letter) that may become payable to you pursuant to that certain Participation Letter dated as of February 26, 2018 and entered into between you and the Company (the "Participation Letter").

By signing below and returning this Retention Bonus Letter to Donna Page, Director, Compensation and Benefits, which must be done within 15 days of the date of this Retention Bonus Letter written above, you acknowledge and agree to all of the terms and conditions set forth herein and confirm that you irrevocably and voluntarily agree to those terms.

Subject to the foregoing, you and the Company (hereinafter referred to as the "parties") hereby agree as follows:

1)Retention Bonus. In recognition of your commitment to the Company and ongoing dedication to its success, the Company is offering you a one-time special cash retention bonus in an amount equal to $500,000¹(the "Retention Bonus"). The Retention Bonus is subject to your continued employment with the Company through March 1, 2019 (the "Retention Date") and shall be paid in a lump sum within 15 days after the Retention Date, provided, however, that if your employment is terminated by the Company without Cause (as defined in the Participation Letter) (and other than due to your death or Disability (as defined in the Participation Letter)) or you resign your employment for Good Reason (as defined in the Participation Letter), in either case prior to the Retention Date and you satisfy the requirements for receiving any Severance Benefits in accordance with the terms of the Participation Letter, including your execution and non-revocation of a release of claims in the form attached as an exhibit to the Participation Letter, a pro-rated amount of the Retention Bonus (which will be based on the number of months (rounded up to the nearest whole month) you remained employed following the date of this Retention Bonus Letter) will be paid to you (the "Pro-Rated Retention Bonus"), in addition to such Severance Benefits, at the same time as the Cash Severance (as defined in the Participation Letter) is paid to you. For the avoidance of doubt, the Pro-Rated Retention Bonus will be paid to you in the event you do not receive certain Severance Benefits as a result of the application of Section 7 of the Participation Letter, provided that you execute and do not revoke a release of claims in the form attached as an exhibit to the Participation Letter. The Retention Bonus is a special payment to you and will not be taken into account in computing the amount of salary or compensation for purposes of determining any bonus, incentive, severance, notice, redundancy, pension, retirement, death or other benefit under any benefit plan or compensation arrangement of the Company, except as expressly required by the terms of such other plan or arrangement.

____________________________

¹ Excludes SERP participants.

2)     Entire Agreement. This Retention Bonus Letter, together with the Participation Letter, represents the entire agreement between you and the Company with respect to the subject matter herein and it supersedes any other promises, warranties or representations with regard to this subject matter.

3)     Section 409A. The intent of the parties is that the payments and benefits under this Retention Bonus Letter comply with or be exempt from Section 409A of the Internal Revenue Code of 1986, as amended, and the regulations and guidance promulgated thereunder (collectively, "Section 409A") and, accordingly, to the maximum extent permitted, this Retention Bonus Letter shall be interpreted to be in compliance therewith. Notwithstanding anything in this Retention Bonus Letter to the contrary, any compensation or benefits payable under this Retention Bonus Letter that is considered nonqualified deferred compensation under Section 409A and is designated under this Retention Bonus Letter as payable upon Participant’s termination of employment shall be payable only upon Participant’s "separation from service" with the Company within the meaning of Section 409A (a "Separation from Service"). In addition, notwithstanding anything in this Retention Bonus Letter to the contrary, if Participant is deemed by the Company at the time of Participant’s Separation from Service to be a "specified employee" for purposes of Section 409A, to the extent delayed commencement of any portion of the benefits to which Participant is entitled under this Retention Bonus Letter is required in order to avoid a prohibited distribution under Section 409A, such portion of Participant’s benefits shall not be provided to Participant prior to the earlier of (i) the expiration of the six-month period measured from the date of Participant’s Separation from Service with the Company or (ii) the date of Participant’s death. Upon the first business day following the expiration of the applicable Section 409A period, all payments deferred pursuant to the preceding sentence shall be paid in a lump sum to Participant (or Participant’s estate or beneficiaries), and any remaining payments due to Participant under this Retention Bonus Letter shall be paid as otherwise provided herein.

4)     Governing Law; Arbitration. The validity, interpretation, construction and performance of this Retention Bonus Letter shall in all respects be governed by the laws of Colorado without reference to principles of conflict of law, except to the extent pre-empted by Federal law. The parties agree that any controversy, claim or dispute arising out of or relating to this Retention Bonus Letter that the parties cannot resolve through negotiation shall be settled solely and exclusively by a binding arbitration process administered by the American Arbitration Association ("AAA") in Denver Colorado. Such arbitration shall be conducted in accordance with the AAA’s then-existing Employment Arbitration Rules. Each party shall bear its own attorney’s fees and expenses and one-half of the fees and expenses of the arbitration; provided, that the arbitrator shall have the authority to apportion the costs of arbitration and to render an award including reasonable attorneys’ fees, as and to the extent the arbitrator deems appropriate under the circumstances. The arbitrator’s decisions and awards will be rendered in a reasoned written opinion, and the parties agree to abide by all such decisions and awards. Such decisions and awards rendered by the arbitrator shall be final and conclusive and may be entered in any court having jurisdiction.

5)     Miscellaneous. All payments to the Participant in accordance with the provisions of the Plan shall be subject to applicable withholding of local, state, Federal and foreign taxes, as determined in the sole discretion of the Company. Except as expressly set forth herein, your employment relationship with the Company remains at will, meaning that either you or the Company may terminate your employment at any time, with or without cause or advance notice. Nothing in this letter is intended to or should be construed to contradict, modify or alter your employment relationship with the Company. The Company’s obligation to make the payments provided for under this Retention Bonus Letter and otherwise to perform its obligations hereunder shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action which the Company may have against a Participant. By accepting this letter, you hereby agree that this letter may only be amended or modified by a written instrument signed by you and a duly authorized representative of the Company. This Retention Bonus Letter shall bind any successor of the Company, its

assets or its businesses (whether direct or indirect, by purchase, merger, consolidation, separation or otherwise), in the same manner and to the same extent that the Company would be obligated under this Retention Bonus Letter if no succession had taken place.

Thank you for your hard work and contributions to the Company.

QEP RESOURCES, INC.

	QEP RESOURCES, INC.
By:	/s/ Charles B. Stanley
	Charles B. Stanley
	Chairman, President and Chief Executive Officer

ACCEPTED AND AGREED TO this ____ day of February 2018.

By:
	[NAME]

EX-10.30

Exhibit 10.30

February 26, 2018

[NAME]

Re: Executive Severance Compensation Program

Dear [NAME]:

This "Participation Letter" confirms the agreement between you (the "Participant") and QEP Resources, Inc. (the "Company") regarding certain severance payments and benefits that will be paid to you in the event your employment with the Company is terminated in accordance with the provisions of this Participation Letter.

By signing below and returning this Participation Letter to Donna Page, Director, Compensation and Benefits, which must be done within 15 days of the date of this Participation Letter written above, you acknowledge and agree to all of the terms and conditions set forth herein and confirm that you irrevocably and voluntarily agree to those terms.

Subject to the foregoing, you and the Company (hereinafter referred to as the "parties") hereby agree as follows:

1)Severance Benefits. In the event the Participant’s employment with the Company is terminated by the Company without Cause (and other than due to the Participant’s death or Disability) or the Participant resigns the Participant’s employment for Good Reason, then, in either case, provided that (i) the Participant signs, within 45 days after the date of termination, and does not revoke a release of claims substantially in the form attached hereto as Exhibit A (the "Release"), (ii) returns to the Company all property belonging to the Company, (iii) until the applicable date(s) of payment complies with any and all confidentiality and other restrictive covenants to which the Participant is subject ("Restrictive Covenants") (provided that nothing herein shall be construed to limit the duration of any restrictive covenants), and (iv) promptly resigns from any position as an officer, director or fiduciary of any subsidiary or affiliate of the Company (and takes any action reasonably requested by the Company to effectuate such resignation), the Participant shall be entitled to receive the following severance payments and benefits (the "Severance Benefits"), which shall be in lieu of and not in addition to any other notice, severance, separation or other similar payments or entitlements under any other plan, program, arrangement or agreement of the Company or any of its affiliates or any applicable law:

a)The Participant shall receive a lump sum cash severance payment (the "Cash Severance") equal to [ ]¹ times the sum of (i) the Participant’s annual base salary, plus (ii) the amount of the Participant’s annual target bonus award opportunity under the Company’s annual cash incentive plan, payable within 30 days after the date the Participant signs the Release, but in no event later than March 15 of the year following the year of termination.

b)The Participant shall receive a pro-rated amount of the Participant’s target bonus amount under the Company’s annual cash incentive plan for the year of termination, payable in cash within 30 days after the date the Participant signs the Release, but in no event later than March 15

____________________________

¹ 1.5 for all Participants other than the Chief Executive Officer and Chief Financial Officer; 2.5 for the Chief Executive Officer; and 2.0 for the Chief Financial Officer.

of the year following the year of termination. Such pro-rated target bonus payment will be based on the number of months the Participant was employed with the Company during the applicable year (rounded up to the nearest whole month).² 

c)     All of the Participant’s outstanding equity and long-term incentive awards shall become fully vested, non-forfeitable and exercisable or payable, as applicable, as of the Participant’s date of termination of employment, provided that, for administrative convenience, the Company shall have a period of 30 days following the date the Participant signs the Release (but not later than March 15 of the year following the year of termination) to implement such vesting, exercisability and/or payment, as applicable, and the Participant’s outstanding stock options shall remain exercisable until the original expiration date of the options (subject to the general terms of the Company’s applicable equity or long-term incentive plan under which such options were granted), provided, however, that the vesting and payment of any "Performance Share Units" shall be based on (i) the actual level of performance in relation to the applicable performance measures, determined as of the last day of the month ended prior to the date of termination (the "PSU Measurement Date") and (ii) as applicable, the Company’s average closing Company stock price for the three month period ending on the PSU Measurement Date, provided, further, that to the extent the applicable performance level cannot be measured prior to the end of the applicable performance period, the payment of Participant’s Performance Share Units shall be based on the actual level of performance achievement at the end of the performance period and made at the regularly scheduled time under the applicable Performance Share Unit award agreement.

d)     The Participant shall receive a lump sum cash payment in an amount equal to twenty four (24)times the monthly premium payment amount required to continue the Participant’s (and, if applicable the Participant’s covered dependents’) medical, dental and vision coverage, as applicable, under the Company’s group healthcare plans pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended ("COBRA"), payable within 30 days after the date the Participant signs the Release, but in no event later than March 15 of the year following the year of termination.

e)     The Participant may use authorized outplacement services provided by the Company’s designated preferred outplacement provider for a period of up to twelve (12) months at no cost to the Participant.

f)     If, and only if, Participant has an accrued vested benefit under the QEP Resources, Inc. Retirement Plan (as amended from time to time and including successor plans, the "Retirement Plan") and/or the QEP Resources, Inc. Supplemental Executive Retirement Plan (as amended from time to time and including successor plans, the "SERP"), then Participant shall be entitled to an enhanced retirement benefit in an amount equal to the excess of (i) the benefit the Participant

____________________________

² For the Chief Executive Officer and Chief Financial Officer, replace with the following provision: The Participant shall receive a pro-rated cash bonus payment under the Company’s annual cash incentive plan for the year of termination, determined at the end of the year and paid in a lump sum at the same time as the Company pays annual bonuses for such year to active Company officers. Such pro-rated cash bonus shall be determined by multiplying the cash bonus award the Participant would have received if the Participant had remained employed through the applicable date of payment by a fraction, the numerator of which is the number of months in the applicable year during which the Participant was employed (rounded up to the nearest whole month) and the denominator of which is 12.

would have accrued under the Retirement Plan and the SERP (if participating) as of the date of termination calculated as if (A) the Participant had been credited with two additional years of benefit service under the Retirement Plan and the SERP (if participating) as of the Date of Termination, and (B) the Participant’s compensation under the Retirement Plan and the SERP (if participating) for each additional year of such service had been equal to the Participant’s compensation for the last full Year prior to the date of termination, over (ii) the actual benefit accrued under the Retirement Plan and the SERP (if participating) as of the Date of Termination. Such enhanced retirement benefit shall be paid in a single lump sum within 30 days after the date the Participant signs the Release, but in no event later than March 15 of the year following the year of termination. The lump-sum payment shall be equal to (i) the present value of the applicable enhanced retirement benefit on the date of termination, calculated using the applicable mortality tables then being used by the Company for financial reporting purposes and an interest rate equal to 80 percent of the average of the IRS 30-year Treasury Securities Rates for the six-month period preceding the participant’s date of termination, plus (ii) interest on such amount, credited monthly from the date of termination through the date of payment (taking into account any delay required by Section 5.7(b)), using the appropriate 30-year Treasury bond rate quoted in the Wall Street Journal on the first business day of each month. The appropriate 30-year Treasury bond shall be the bond that has the closest maturity date (by month) preceding the month in which interest is to be credited.

2)     Definitions. For purposes of this Participation Letter, the following definitions shall apply:

a)"Cause" means the Participant’s: (i) conviction of a felony, or of a misdemeanor involving fraud, moral turpitude or dishonesty; (ii) gross neglect or willful and continued failure to perform substantially the Participant’s duties for the Company (other than any such failure resulting from incapacity due to physical or mental illness), which continues following written demand for substantial performance delivered to the Participant by the Company’s Board of Directors (the "Board") or the Chief Executive Officer of the Company and a reasonable opportunity to cure; (iii) violation of any Restrictive Covenants; (iv) willful failure to comply with Board directives or material Company policies, following written demand for compliance delivered to the Participant by the Board or the Chief Executive Officer of the Company and a reasonable opportunity to cure; or (v) the willful engaging by the Participant in fraud or misconduct that materially and adversely affects the Participant’s Employer or the Company. For purposes of this definition, no act or failure to act on the part of the Participant shall be considered "willful" unless it is done, or omitted to be done, by the Participant without reasonable belief that the Participant’s action or omission was in the best interests of the Company. The Company, acting through the Board, must notify the Participant in writing that the Participant’s employment is being terminated for "Cause". The notice shall include a list of the factual findings used to sustain the judgment that the Participant’s employment is being terminated for "Cause."

b)"Disability" means a condition resulting in the Participant’s receipt of payments for disability under the QEP Resources, Inc. Long-term Disability Plan or any plan providing similar long-term disability benefits sponsored by the Company or its affiliate.

c)     "Good Reason" means any of the following events or conditions that occur without the Participant’s written consent, and that remain in effect after notice has been provided by the Participant to the Company of such event or condition and the expiration of a 30 day cure period: (i) a material diminution in the Participant’s base salary, target bonus opportunity under the Company’s annual incentive plan, or target annual award opportunity under the Company’s long-term incentive compensation plans, it being understood that any such diminution that results in a reduction in total target annual compensation of 5% or more shall be deemed material; (ii) a material diminution in the Participant’s authority, duties, or responsibilities (which shall include a change in reporting structure that requires the Participant to report to a supervisor having materially less authority within the Company, it being understood that a mere change in the identity or role of the Participant’s supervisor shall not constitute Good Reason hereunder). For the avoidance of doubt, a diminution in the Participant’s authority, duties or responsibilities arising as a sole result of the divestiture of assets shall not constitute Good Reason hereunder; or (iii) a material change in the geographic location at which the Participant is required to perform services. The Participant’s notification to the Company must be in writing and must occur within a reasonable period of time, not to exceed 60 days, following the date the Participant knew or should have known of the existence of the relevant event or condition.

3)     Entire Agreement. This Participation Letter represents the entire agreement between you and the Company with respect to the subject matter herein and it supersedes any other promises, warranties or representations with regard to this subject matter. However, for the avoidance of doubt, this Participation Letter does not supersede the QEP Resources, Inc. Executive Severance Compensation Plan - CIC (the "CIC Plan").

4)     Expiration. This letter and your right to receive the Severance Benefits will expire and terminate, and be of no further force or effect, on September 30, 2020. In addition, in the event a Change in Control (as defined in the CIC Plan) occurs, you will no longer be eligible to receive the Severance Benefits under this Participation Letter and will instead be eligible to receive Separation Benefits (as defined in the CIC Plan) under the CIC Plan.

5)     Section 409A. The intent of the parties is that the payments and benefits under this Participation Letter comply with or be exempt from Section 409A of the Internal Revenue Code of 1986, as amended, and the regulations and guidance promulgated thereunder (collectively, "Section 409A") and, accordingly, to the maximum extent permitted, this Participation Letter shall be interpreted to be in compliance therewith. Notwithstanding anything in this Participation Letter to the contrary, any compensation or benefits payable under this Participation Letter that is considered nonqualified deferred compensation under Section 409A and is designated under this Participation Letter as payable upon Participant’s termination of employment shall be payable only upon Participant’s "separation from service" with the Company within the meaning of Section 409A (a "Separation from Service"). In addition, notwithstanding anything in this Participation Letter to the contrary, if Participant is deemed by the Company at the time of Participant’s Separation from Service to be a "specified employee" for purposes of Section 409A, to the extent delayed commencement of any portion of the benefits to which Participant is entitled under this Participation Letter is required in order to avoid a prohibited distribution under Section 409A, such portion of Participant’s benefits shall not be provided to Participant prior to the earlier of (i) the expiration of the six-month period measured from the date of Participant’s Separation from Service with the Company or (ii) the date of Participant’s death. Upon the first business day following the expiration of the applicable Section 409A period, all payments deferred pursuant to the preceding sentence shall be paid in a lump sum

to Participant (or Participant’s estate or beneficiaries), and any remaining payments due to Participant under this Participation Letter shall be paid as otherwise provided herein.

6)     Governing Law; Arbitration. The validity, interpretation, construction and performance of this Participation Letter shall in all respects be governed by the laws of Colorado without reference to principles of conflict of law, except to the extent pre-empted by Federal law. The parties agree that any controversy, claim or dispute arising out of or relating to this Participation Letter that the parties cannot resolve through negotiation shall be settled solely and exclusively by a binding arbitration process administered by the American Arbitration Association ("AAA") in Denver Colorado. Such arbitration shall be conducted in accordance with the AAA’s then-existing Employment Arbitration Rules. Each party shall bear its own attorney’s fees and expenses and one-half of the fees and expenses of the arbitration; provided, that the arbitrator shall have the authority to apportion the costs of arbitration and to render an award including reasonable attorneys’ fees, as and to the extent the arbitrator deems appropriate under the circumstances. The arbitrator’s decisions and awards will be rendered in a reasoned written opinion, and the parties agree to abide by all such decisions and awards. Such decisions and awards rendered by the arbitrator shall be final and conclusive and may be entered in any court having jurisdiction.

7)     Divestiture. Notwithstanding any provision herein to the contrary, in the event of a divestiture or other similar transaction (a "Divestiture") pursuant to which the Company sells any line of business or material assets to a third-party buyer ("Buyer") and in connection with such Divestiture, (i) the Buyer offers to employ the Participant in a comparable role or position and (ii) the Participant accepts such offer of employment and/or commences employment with the Buyer following the closing of the Divestiture, then the Participant will not be entitled to receive the Severance Benefits described in Section 1(a), (d) or (e) of this Participation Letter if the Participant’s employment with the Company terminates in connection with such Divestiture.

8)     Miscellaneous. All payments to the Participant in accordance with the provisions of the Plan shall be subject to applicable withholding of local, state, Federal and foreign taxes, as determined in the sole discretion of the Company. Except as expressly set forth herein, your employment relationship with the Company remains at will, meaning that either you or the Company may terminate your employment at any time, with or without cause or advance notice. Nothing in this letter is intended to or should be construed to contradict, modify or alter your employment relationship with the Company. The Company’s obligation to make the payments provided for under this Participation Letter and otherwise to perform its obligations hereunder shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action which the Company may have against a Participant. By accepting this letter, you hereby agree that this letter may only be amended or modified by a written instrument signed by you and a duly authorized representative of the Company. This Participation Letter shall bind any successor of the Company, its assets or its businesses (whether direct or indirect, by purchase, merger, consolidation, separation or otherwise), in the same manner and to the same extent that the Company would be obligated under this Participation Letter if no succession had taken place.

Thank you for your hard work and contributions to the Company.

	QEP RESOURCES, INC.
By:
	[NAME]
	[TITLE]

ACCEPTED AND AGREED TO this ____ day of February 2018.

By:
	[NAME]

EXHIBIT A

Form of Release of Claims

[The language in this Release may change based on legal developments and evolving best practices; this form is provided as an example of what will be included in the final Release document.]

This General Release of Claims ("Release") is entered into as of this _____ day of ________, ____, between ________ ("Executive"), and [_______________], a [______] corporation (the "Company") (collectively referred to herein as the "Parties").

WHEREAS, Executive and the Company are parties to that certain Participation Letter dated as of __________, ____ (the "Agreement");

WHEREAS, the Parties agree that Executive is entitled to certain severance benefits under the Agreement, subject to Executive’s execution of this Release; and

WHEREAS, the Company and Executive now wish to fully and finally resolve all matters between them.

NOW, THEREFORE, in consideration of, and subject to, the severance benefits payable to Executive pursuant to the Agreement, the adequacy of which is hereby acknowledged by Executive, and which Executive acknowledges that he or she would not otherwise be entitled to receive, Executive and the Company hereby agree as follows:

1.    General Release of Claims by Executive.

(a)    Executive, on behalf of himself or herself and his or her executors, heirs, administrators, representatives and assigns, hereby agrees to release and forever discharge the Company and all predecessors, successors and their respective parent corporations, affiliates, related, and/or subsidiary entities, and all of their past and present investors, directors, shareholders, officers, general or limited partners, employees, attorneys, creditors, agents and representatives, and the employee benefit plans in which Executive is or has been a participant by virtue of his or her employment with or service to the Company (collectively, the "Company Releasees"), from any and all claims, debts, demands, accounts, judgments, rights, causes of action, equitable relief, damages, costs, charges, complaints, obligations, promises, agreements, controversies, suits, expenses, compensation, responsibility and liability of every kind and character whatsoever (including attorneys’ fees and costs), whether in law or equity, known or unknown, asserted or unasserted, suspected or unsuspected (collectively, "Claims"), which Executive has or may have had against such entities based on any events or circumstances arising or occurring on or prior to the date hereof, arising directly or indirectly out of, relating to, or in any other way involving in any manner whatsoever Executive’s employment by or service to the Company or the termination thereof, including any and all claims arising under federal, state, or local laws relating to employment, including without limitation claims of wrongful discharge, breach of express or implied contract, fraud, misrepresentation, defamation, or liability in tort, and claims of any kind that may be brought in any court or administrative agency including, without limitation, claims under Title VII of the Civil Rights Act of 1964, as amended, 42 U.S.C. Section 2000, etseq.; the Americans with Disabilities Act, as amended, 42 U.S.C. § 12101 etseq.; the Rehabilitation Act of 1973, as amended, 29 U.S.C. § 701 etseq.; the Civil Rights Act of 1866, and the Civil Rights Act of 1991; 42 U.S.C. Section 1981, etseq.; the Age Discrimination in Employment Act, as amended, 29 U.S.C. Section 621, etseq. (the "ADEA"); the Equal Pay Act, as amended, 29 U.S.C. Section 206(d); regulations of the Office of Federal Contract Compliance, 41 C.F.R. Section 60, etseq.; the Family and Medical Leave Act, as amended,

29 U.S.C. § 2601 etseq.; the Fair Labor Standards Act of 1938, as amended, 29 U.S.C. § 201 etseq.; the Employee Retirement Income Security Act, as amended, 29 U.S.C. § 1001 etseq.; and any similar state or local law.

Notwithstanding the generality of the foregoing, Executive does not release the following:

(i)    Claims for unemployment compensation or any state disability insurance benefits pursuant to the terms of applicable state law;

(ii)    Claims for workers’ compensation insurance benefits under the terms of any worker’s compensation insurance policy or fund of the Company;

(iii)    Claims pursuant to the terms and conditions of the federal law known as COBRA;

(iv)    Claims for indemnity under the bylaws of the Company or its affiliates, as provided for by law or under any applicable insurance policy with respect to Executive’s liability as an employee, director or officer of the Company pursuant to which Executive is covered as of the effective date of Executive’s termination of employment with the Company and its subsidiaries;

(v)    Claims based on any right Executive may have to enforce the Company’s executory obligations under the Agreement;

(vi)    Claims Executive may have to vested or earned compensation and benefits; and

(vii)    Any rights that cannot be released as a matter of applicable law, but only to the extent such rights may not be released under such applicable law.

(b)    Executive acknowledges that this Release was presented to him or her on the date indicated above and that Executive is entitled to have [twenty-one (21)/forty-five (45)] days’ time in which to consider it. Executive further acknowledges that the Company has advised him or her that he or she is waiving his or her rights under the ADEA, and that Executive should consult with an attorney of his or her choice before signing this Release, and Executive has had sufficient time to consider the terms of this Release. Executive represents and acknowledges that if Executive executes this Release before [twenty-one (21)/forty-five (45)] days have elapsed, Executive does so knowingly, voluntarily, and upon the advice and with the approval of Executive’s legal counsel (if any), and that Executive voluntarily waives any remaining consideration period.

(c)     Executive understands that after executing this Release, Executive has the right to revoke it within seven (7) days after his or her execution of it. Executive understands that this Release will not become effective and enforceable unless the seven (7) day revocation period passes and Executive does not revoke the Release in writing. Executive understands that this Release may not be revoked after the seven (7) day revocation period has passed. Executive also understands that any revocation of this Release must be made in writing and delivered to the Company at its principal place of business within the seven (7) day period.

(d)     Executive understands that this Release shall become effective, irrevocable, and binding upon Executive on the eighth (8th) day after his or her execution of it, so long as Executive has not revoked it within the time period and in the manner specified in clause (c) above.

2.    No Assignment. Executive represents and warrants to the Company Releasees that there has been no assignment or other transfer of any interest in any Claim that Executive may have against the

Company Releasees. Executive agrees to indemnify and hold harmless the Company Releasees from any liability, claims, demands, damages, costs, expenses and attorneys’ fees incurred as a result of any such assignment or transfer from Executive.

3.    Restrictive Covenants.

(a)    Confidential Records and Information.    Executive agrees that Executive will not, unless required or otherwise permitted by law, disclose or divulge to any other person or entity, directly or indirectly, any confidential records or information regarding the Company, including but not limited to the following: (i) practices, policies and or procedures; (ii) trade secrets; (iii) customer names; (iv) any information regarding existing or prospective future business, planning, or development; (v) contracts or proposed contracts; (vi) financial information; (vii) staffing or personnel utilization; (viii) salary or wage levels; (ix) privileged communications; and (x) other information deemed confidential or proprietary not herein listed. Executive covenants that he has returned to the Company, its computers (including data stored thereon) and peripherals, Company credit and fuel cards, and keys. Executive may retain incidental materials he currently has in his possession, or which may be stored incidentally in electronic formats (for example, emails, correspondence, draft documents, copies of various materials accumulated while employed), provided he has not systematically and intentionally acquired any such materials in preparation for Executive’s termination of employment. Executive represents and warrants that in the event he has any Company work related materials, he has no intention of utilizing said materials, nor of disclosing same to any other person or entity.

(b)    Non-solicitation. For a period of twelve (12) months after the date of Executive’s termination of employment, Executive agrees not to induce, attempt to induce or solicit any employee of the Company to leave the employ of the Company or any of its related entities, or hire any such employee in any business or other capacity. Notwithstanding the foregoing, if any employee of the Company initiates contact with Employee as a result of a publically advertised position for purposes of obtaining employment with Executive or Executive’s place of business, such action shall not constitute a breach of this Section 3(b).

4.    Severability. In the event any provision of this Release is found to be unenforceable by an arbitrator or court of competent jurisdiction, such provision shall be deemed modified to the extent necessary to allow enforceability of the provision as so limited, it being intended that the Parties shall receive the benefit contemplated herein to the fullest extent permitted by law. If a deemed modification is not satisfactory in the judgment of such arbitrator or court, the unenforceable provision shall be deemed deleted, and the validity and enforceability of the remaining provisions shall not be affected thereby.

5.    Interpretation; Construction. The headings set forth in this Release are for convenience only and shall not be used in interpreting this agreement. This Release has been drafted by legal counsel representing the Company, but Executive has participated in the negotiation of its terms. Furthermore, Executive acknowledges that Executive has had an opportunity to review and revise the Release and have it reviewed by legal counsel, if desired, and, therefore, the normal rule of construction to the effect that any ambiguities are to be resolved against the drafting party shall not be employed in the interpretation of this Release. Either party’s failure to enforce any provision of this Release shall not in any way be construed as a waiver of any such provision, or prevent that party thereafter from enforcing each and every other provision of this Release.

6.    Governing Law; Arbitration. This Release will be governed by and construed in accordance with the laws of the United States of America and the State of Colorado applicable to contracts made and to be performed wholly within such State, and without regard to the conflicts of laws principles thereof. The parties agree that any controversy, claim or dispute arising out of or relating to this Agreement that the parties

cannot resolve through negotiation shall be settled solely and exclusively by a binding arbitration process administered by the American Arbitration Association ("AAA") in Denver Colorado. Such arbitration shall be conducted in accordance with the AAA’s then-existing Employment Arbitration Rules. Each party shall bear its own attorney’s fees and expenses and one-half of the fees and expenses of the arbitration; provided, that the arbitrator shall have the authority to apportion the costs of arbitration and to render an award including reasonable attorneys’ fees, as and to the extent the arbitrator deems appropriate under the circumstances. The arbitrator’s decisions and awards will be rendered in a reasoned written opinion, and the parties agree to abide by all such decisions and awards. Such decisions and awards rendered by the arbitrator shall be final and conclusive and may be entered in any court having jurisdiction.

7.    Entire Agreement. This Release and the Agreement constitute the entire agreement of the Parties in respect of the subject matter contained herein and therein and supersede all prior or simultaneous representations, discussions, negotiations and agreements, whether written or oral. This Release may be amended or modified only with the written consent of Executive and an authorized representative of the Company. No oral waiver, amendment or modification will be effective under any circumstances whatsoever.

8.    Counterparts. This Release may be executed in multiple counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument.

IN WITNESS WHEREOF, and intending to be legally bound, the Parties have executed the foregoing Release as of the date first written above.

EXECUTIVE		[ ]
	By:
Print Name:	Print Name:
	Title:

EX-10.31

Exhibit 10.31

QEP RESOURCES, INC.

1050 17th Street

Denver, CO 80265

February 28, 2018

Elliott Management Corporation

40 West 57th Street

New York, NY 10019-4001

Attention: Andrew Taylor

Ladies and Gentlemen:

This letter (this "Agreement") constitutes the agreement between Elliott Management Corporation ("Elliott") and QEP Resources, Inc. (the "Company"). Each of Elliott and the Company is individually a "Party" and collectively they are the "Parties." Capitalized terms used and not otherwise defined have the meanings ascribed to them in paragraph 6 of this Agreement.

1.    Promptly following the execution and delivery of this Agreement (but in any event within one (1) business day after the date of this Agreement), the Company shall issue a press release in the form attached to this Agreement as Exhibit A (the "Company Press Release") and each Party shall not, and shall cause its Affiliates and its and their respective principals, directors, members, general partners, officers, employees and agents and representatives acting on their behalf not to, make any statement inconsistent with the Company Press Release in connection with the announcement of this Agreement. Elliott shall not, and shall cause its other Restricted Persons (as defined below) not to, issue any press release in connection with the execution of this Agreement. Additionally, promptly following the execution and delivery of this Agreement (but in any event within one (1) business day after the date of this Agreement), the Company shall file a Current Report on Form 8-K (the "Company 8-K") and/or an Annual Report on Form 10-K (the "Company 10-K"), which shall report the entry into this Agreement. Each of the Form 8-K and Form 10-K shall be consistent with the Company Press Release and the terms of this Agreement.

2.    In the Company’s Proxy Statement for the 2018 Annual Meeting, the Company’s stockholders will be asked to vote on a binding amendment to the Company’s Amended and Restated Certificate of Incorporation effecting an immediate declassification of the Company’s Board of Directors (the "Board") to provide for the annual election of all directors (the "Declassification Amendment"), and management and the Board shall recommend that the Company’s stockholders vote in favor of approving the Declassification Amendment.  The Declassification Amendment will be presented to the Company’s stockholders for vote at the 2018 Annual Meeting. In connection with the Declassification Amendment, all of the current members of the Board, other than Mr. Thacker, will tender their resignations prior to the 2018 Annual Meeting, to be effective prior to the vote for directors at such meeting with the intention that should the Declassification Amendment be approved by the Company’s stockholders, all of the directors (other than Mr. Thacker) shall serve until the 2019 Annual Meeting, or until their

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earlier resignation or retirement from the Board, and that Mr. Thacker will serve his remaining term which expires at the 2019 Annual Meeting.

3.    In connection with the 2018 Annual Meeting (and any adjournments or postponements), the Company shall (a) recommend that the Company’s stockholders vote in favor of the election of each of the Company’s nominees and the approval of the Declassification Amendment, (b) solicit proxies for the election of each of the Company’s nominees and the approval of the Declassification Amendment, (c) cause all Company common stock represented by proxies granted to it (or any of its officers, directors or representatives) to be voted in favor of approval of the Declassification Amendment, and (d) cause all Company common stock represented by proxies granted to it (or any of its officers, directors or representatives) to be voted in favor of each of the Company’s nominees. In connection with the 2018 Annual Meeting (and any adjournments or postponements), Elliott shall cause to be present for quorum purposes and vote or cause to be voted any Company common stock that Elliott or its controlling or controlled Affiliates has the right to vote on the record date for the 2018 Annual Meeting and is beneficially owned by Elliott or its controlling or controlled Affiliates in favor of (i) the Declassification Amendment, (ii) the election of directors nominated by the Board, and (iii) otherwise in accordance with the Board’s recommendation on any other proposals not related to an Extraordinary Transaction (as defined below).

4.    From the date of this Agreement until the Expiration Date or until such earlier time as the restrictions in this paragraph 4 terminate as provided herein (such period, the "Restricted Period"), Elliott shall not, and shall cause its Affiliates and its and their respective principals, directors, general partners, officers, employees, and agents and representatives acting on their behalf (collectively, "Restricted Persons") not to, directly or indirectly, absent prior express written invitation or authorization by the Board:

(a) engage in any "solicitation" (as such term is used in the proxy rules of the SEC) of proxies or consents with respect to the election or removal of directors of the Company or any of its subsidiaries or any other matter or proposal relating to the Company or any of its subsidiaries or become a "participant" (as such term is used in the proxy rules of the SEC) in any such solicitation of proxies or consents;

(b) knowingly encourage or advise any Person or knowingly assist any Person in encouraging or advising any other Person (i) with respect to the giving or withholding of any proxy or consent relating to, or other authority to vote, any Voting Securities, or (ii) in conducting any type of referendum relating to the Company or any of its subsidiaries (other than such encouragement or advice that is consistent with management’s recommendation in connection with a particular matter);

(c) form, join or act in concert with any "group" as defined pursuant to Section 13(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), with respect to any Voting Securities, other than solely with Affiliates of Elliott with respect to Voting Securities now or hereafter owned by them;

(d) acquire, or offer, seek or agree to acquire, by purchase or otherwise, or direct any Third Party in the acquisition of, any Voting Securities of the Company, or engage in any swap or hedging transactions or other derivative agreements of any nature with respect to Voting Securities, in each case, if such acquisition, offer, agreement or transaction would

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result in Elliott having a Net Long Position of, or voting rights (or the right to acquire voting rights) with respect to, more than 9.9% of the Voting Securities of the Company;

(e) sell, offer or agree to sell, all or substantially all, directly or indirectly, through swap or hedging transactions or otherwise, voting rights decoupled from the underlying common stock of the Company held by Elliott to any Third Party;

(f) make or in any way participate, either alone or in concert with others, directly or indirectly, in any tender offer, exchange offer, merger, consolidation, acquisition, business combination, purchase of a division, purchase of all or substantially all of the assets, recapitalization, restructuring, liquidation, dissolution or similar extraordinary transaction involving the Company or any of its subsidiaries or its or their respective securities or assets (each, an "Extraordinary Transaction") (it being understood that the foregoing shall not restrict the Restricted Persons from tendering shares, receiving payment for shares or otherwise participating in any Extraordinary Transaction initiated by a Third Party on the same basis as other stockholders of the Company or any of its subsidiaries, or from participating in any Extraordinary Transaction that has been approved by the Board or the board of any subsidiary of the Company), provided that in no case will any asset sales (or series of asset sales) consistent with the strategic initiatives announced in the Company Press Release be an Extraordinary Transaction; or make, directly or indirectly, any proposal, either alone or in concert with others, to the Company or any of its subsidiaries or the Board or the board of any subsidiary of the Company that would reasonably be expected to require the Company or Elliott to make a public announcement regarding any of the types of matters set forth above in this clause (f);

(g) enter into a voting trust, arrangement or agreement with respect to any Voting Securities, or subject any Voting Securities to any voting trust, arrangement or agreement other than (i) this Agreement, (ii) solely with Affiliates of Elliott, or (iii) granting proxies in solicitations approved by the Board or the board of any subsidiary of the Company;

(h) (i) seek, alone or in concert with others, election or appointment to, or representation on, the Board or the board of any subsidiary of the Company or nominate or propose the nomination of, or recommend the nomination of, any candidate to the Board or any such other board, (ii) seek, alone or in concert with others, the removal of any member of the Board or any such other board, or (iii) conduct a referendum of stockholders of the Company or any of its subsidiaries; provided that nothing in this Agreement shall prevent Elliott or its Affiliates from taking actions confidentially in furtherance of identifying director candidates in connection with the 2019 Annual Meeting so long as such actions do not create a public disclosure obligation for Elliott or the Company and are undertaken on a confidential basis and in accordance in all material respects with Elliott’s normal practices in the circumstances;

(i) make or be the proponent of any stockholder proposal (pursuant to Rule 14a-8 under the Exchange Act or otherwise) relating to the Company or any of its subsidiaries;

(j) make any request for stock list materials or other books and records of the Company or any of its subsidiaries under Section 220 of the General Corporation Law of the State of Delaware or other statutory or regulatory provisions providing for shareholder access to books and records;

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(k) except as set forth herein, make any public proposal with respect to (i) any change in the number or term of directors or the filling of any vacancies on the Board or the board of any subsidiary of the Company, (ii) any material change in the capitalization or dividend policy of the Company or any of its subsidiaries, (iii) any other material change in management, business or corporate structure of the Company or any of its subsidiaries, or in the ability of the Company to engage in a future change of control transaction, (iv) any waiver, amendment or modification to the certificate of incorporation or bylaws ("Governing Documents") of the Company or any of its subsidiaries, (v) causing a class of securities of the Company or any of its subsidiaries to be delisted from, or to cease to be authorized to be quoted on, any securities exchange or (vi) causing a class of equity securities of the Company or any of its subsidiaries to become eligible for termination of registration pursuant to Section 12(g)(4) of the Exchange Act;

(l) institute, solicit, assist or join any litigation, arbitration or other proceeding against or involving the Company or any of its subsidiaries or any of its or their respective current or former directors or officers (including derivative actions) in order to effect or take any of the actions expressly prohibited by this paragraph 4; provided, however, that for the avoidance of doubt, the foregoing shall not prevent any Restricted Person from (i) instituting litigation to enforce the provisions of this Agreement; (ii) making counterclaims with respect to any proceeding initiated by, or on behalf of, the Company against a Restricted Person, (iii) bringing bona fide commercial disputes that do not relate to the subject matter of this Agreement, or (iv) exercising statutory appraisal rights; provided, further, that the foregoing shall also not prevent the Restricted Persons from responding to or complying with a validly issued legal process;

(m) enter into any negotiations, agreements or understandings with any Third Party to take any action that Elliott is prohibited from taking pursuant to this paragraph 4;

(n) publicly disclose any intention, plan or arrangement inconsistent with any provision of this paragraph 4; or

(o) make any request or submit any proposal to amend or waive the terms of this Agreement, in each case which would reasonably be expected to result in a public announcement of such request or proposal;

provided that (A) the restrictions in this paragraph 4 shall terminate automatically upon the earliest of: (i) as a nonexclusive remedy for any such breach, five (5) business days after written notice is delivered to the Company by Elliott following a material breach of this Agreement by the Company if such breach has not been cured within such notice period; provided further, that Elliott is not in material breach of this Agreement at the time such notice is given; (ii) the announcement by the Company that it (x) has entered into a definitive agreement, or (y) is negotiating with any Third Party regarding a commercially reasonable offer (which it intends to

4

pursue in good faith to enter into an Extraordinary Transaction), in each case with respect to any Extraordinary Transaction that would result in the acquisition by any Person of more than 50% of the Voting Securities of the Company; (iii) the commencement of any tender or exchange offer (by any Person other than Elliott or its Affiliates) which, if consummated, would constitute an Extraordinary Transaction that would result in the acquisition by any Person of more than 50% of the Voting Securities, where the Company files with the SEC a Schedule 14D-9 (or any amendment thereto) that does not recommend that its stockholders reject such tender or exchange offer (provided that nothing herein shall prevent the Company from issuing a “stop, look and listen” communication pursuant to Rule 14d-9(f) promulgated under the Exchange Act in response to the commencement of any tender or exchange offer); (iv) the public announcement by the Company that it is exploring or may explore strategic alternatives for an Extraordinary Transaction, including by conducting a strategic review process or similar evaluation, (v) such time as the Company files with the SEC or delivers to its stockholders any preliminary proxy statement, definitive proxy statement or other proxy materials in connection with the 2018 Annual Meeting that is inconsistent with the terms of this Agreement; (vi) the adoption by the Board of any amendment to the Company’s Governing Documents, each as in effect on the date hereof, that would reasonably be expected to impair the ability of a stockholder to submit nominations of individuals for election to the Board or stockholder proposals in connection with any Annual Meeting after the 2018 Annual Meeting; and (vii) the adoption of any shareholder rights plan (unless such rights plan has a trigger in excess of 10% of the common stock of the Company outstanding and is adopted (x) in response to an accumulation by a Third Party, or (y) in response to an unsolicited proposal for an Extraordinary Transaction); and (B) nothing in this paragraph 4 or paragraph 5 shall prevent Elliott from making (i) any public or private statement or announcement with respect to any Extraordinary Transaction that is publicly announced by the Company or a Third Party, or (ii) any factual statement made to comply with any subpoena or other legal process or respond to a request for information from any governmental authority with jurisdiction over Elliott from whom information is sought (so long as such process or request did not arise as a result of discretionary acts by Elliott or any of its Affiliates). Notwithstanding the foregoing, nothing in this Agreement shall restrict the ability of the Restricted Persons to grant any liens or encumbrances on any claims or interests in favor of a bank or broker-dealer or prime broker holding such claims or interests in custody or prime brokerage in the ordinary course of business, which lien or encumbrance is released upon the transfer of such claims or interests in accordance with the terms of the custody or prime brokerage agreement(s), as applicable.

5.    During the Restricted Period, each of the Company and Elliott shall refrain from making, and shall cause their respective Affiliates and its and their respective principals, directors, members, general partners, officers, employees and agents and representatives acting on their behalf not to make or cause to be made any statement or announcement, including in any document or report filed with or furnished to the SEC or through the press, media, analysts or other Persons, that constitutes an ad hominem attack on, or otherwise disparages, defames, slanders, impugns or is reasonably likely to damage the reputation of, (a) in the case of statements or announcements by any of Elliott, the Company or any of its Affiliates, subsidiaries or advisors, or any of its or their respective current or former officers, directors or employees, and (b) in the case of statements or announcements by the Company, Elliott and Elliott’s advisors, their respective employees or any individual who has served as an employee of Elliott and Elliott’s advisors. The foregoing shall not (i) restrict the ability of any Person to comply with

5

any subpoena or other legal process or respond to a request for information from any governmental authority with jurisdiction over the Person from whom information is sought or (ii) apply to any private communications between Elliott, its Affiliates and its and their respective principals, directors, members, general partners, officers, employees or agents or representatives acting on their behalf, on the one hand, and the Company or any of its subsidiaries, directors, officers, employees or agents or representatives acting on their behalf, on the other hand.

6.    As used in this Agreement, the term (a) "Affiliate" shall have the meaning set forth in Rule 12b-2 promulgated under the Exchange Act and shall include Persons who become Affiliates of any Person subsequent to the date of this Agreement; provided that "Affiliates" of a Person shall not include any entity, solely by reason of the fact that one or more of such Person’s employees or principals serves as a member of its board of directors or similar governing body, unless such Person otherwise controls such entity (as the term "control" is defined in Rule 12b-2 promulgated by the SEC under the Exchange Act); provided further that with respect to Elliott "Affiliates" shall not include any portfolio operating company of Elliott or its Affiliates; (b) "Annual Meeting" shall mean the annual meeting of stockholders of the Company, and any reference to an Annual Meeting preceded by a calendar year (e.g., "2018") shall mean the Annual Meeting to occur during such calendar year; (c) "beneficially own", "beneficially owned" and "beneficial ownership" shall have the meaning set forth in Rules 13d-3 and 13d-5(b)(l) promulgated under the Exchange Act; (d) "business day" shall mean any day other than a Saturday, Sunday or a day on which the Federal Reserve Bank of New York is closed; (e) "controlled," "controlling" and "controlled by" shall have the meanings set forth in Rule 12b-2 promulgated under the Exchange Act; (f) "Expiration Date" shall mean the earlier of (i) January 15, 2019, and (ii) thirty (30) days prior to the first day of the time period established pursuant to the Company’s bylaws for stockholders to deliver notice to the Company of director nominations to be brought before the 2019 Annual Meeting; (g) "Net Long Position" shall mean, with respect to any Person, such Person’s net long position, as defined in Rule 14e-4 under the Exchange Act, mutatis mutandis, in respect of the Company’s common stock; provided that, for the avoidance of doubt, "Net Long Position" will not include any shares as to which such Person does not have the right to vote or direct the vote or as to which such Person has entered into a derivative contract or other agreement, arrangement or understanding that hedges or transfers, in whole or in part, any of the economic consequences of ownership of such shares; (h) "Person" shall be interpreted broadly to include, among others, any individual, general or limited partnership, corporation, limited liability or unlimited liability company, joint venture, estate, trust, group, association or other entity of any kind or structure; (i) "SEC" means the United States Securities and Exchange Commission; (j) "Third Party" shall mean any Person that is not a Party or an Affiliate thereof, a member of the Board, a director or officer of the Company, or legal counsel to any Party; and (k) "Voting Securities" shall mean the shares of common stock of the Company and any other securities thereof entitled to vote in the election of directors, or securities convertible into, or exercisable or exchangeable for, such shares or other securities, whether or not subject to the passage of time or other contingencies; provided that "Voting Securities" shall not include any securities contained in any index, exchange traded fund, benchmark or other industry-related basket of at least ten securities.

7.    Elliott represents, warrants and agrees that (a) this Agreement has been duly authorized, executed and delivered by it and is a valid and binding obligation of Elliott, enforceable against it in accordance with its terms; (b) as of the date of this Agreement, Elliott

6

beneficially owns an aggregate of 11,700,000 shares of Voting Securities of the Company, of which 10,500,000 are shares of common stock of the Company; and (c) this Agreement does not violate any law, any order of any court or other agency of government, or Elliott’s organizational documents, each as in effect on the date of this Agreement.

8.    The Company represents and warrants that (a) this Agreement has been duly authorized, executed and delivered by it and is a valid and binding obligation of the Company, enforceable against the Company in accordance with its terms; (b) this Agreement does not require the approval of the stockholders of the Company; and (c) this Agreement does not violate any law, any order of any court or other agency of government, or the Company’s Governing Documents, each as in effect on the date of this Agreement.

9.    Each Party acknowledges that (i) the other Party would be irreparably injured by a breach of this agreement and (ii) monetary remedies may be inadequate to protect a party against any actual or threatened breach or continuation of any breach of this agreement. Without prejudice to any other rights and remedies otherwise available to a Party under this agreement, (a) each Party shall be entitled to seek equitable relief by way of injunction or otherwise to prevent breaches or threatened breaches of any of the provisions of this Agreement, without proof of actual damages; (b) the breaching Party shall not plead in defense thereto that there would be an adequate remedy at law; and (c) the breaching Party agrees to waive any applicable right or requirement that a bond be posted by the non-breaching Party. Such remedies shall not be the exclusive remedies for a breach of this Agreement, but shall be in addition to all other remedies available at law or in equity. This Agreement is solely for the benefit of the Parties and shall not be enforceable by any other Person.

10.    This Agreement constitutes the only agreement between Elliott and the Company with respect to the subject matter hereof and supersedes all prior agreements, understandings, negotiations and discussions, whether oral or written. This Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns. No Party may assign or otherwise transfer either this Agreement or any of its rights, interests, or obligations under this Agreement without the prior written approval of the other Party. Any purported transfer requiring consent without such consent shall be void. No amendment, modification, supplement or waiver of any provision of this Agreement shall be effective unless it is in writing and signed by the Party affected thereby, and then only in the specific instance and for the specific purpose stated therein. Any waiver by any Party of a breach of any provision of this Agreement shall not operate as or be construed to be a waiver of any other breach of such provision or of any breach of any other provision of this Agreement. The failure of a Party to insist upon strict adherence to any term of this Agreement on one or more occasions shall not be considered a waiver or deprive that Party of the right thereafter to insist upon strict adherence to that term or any other term of this Agreement. If any provision of this Agreement is held invalid or unenforceable by any court of competent jurisdiction, the other provisions of this Agreement shall remain in full force and effect. Any provision of this Agreement held invalid or unenforceable only in part or degree shall remain in full force and effect to the extent not held invalid or unenforceable. The Parties further agree to replace such invalid or unenforceable provision of this Agreement with a valid and enforceable provision that will achieve, to the extent possible, the purposes of such invalid or unenforceable provision. All attorneys’ fees, costs and expenses incurred in connection with this Agreement and all matters related hereto will be paid by the Party incurring such fees, costs or expenses. Each of the

7

parties acknowledges that it has been represented by counsel of its choice throughout all negotiations that have preceded the execution of this Agreement, and that it has executed this Agreement with the advice of such counsel. Each Party and its counsel cooperated and participated in the drafting and preparation of this Agreement, and any and all drafts relating thereto exchanged among the Parties shall be deemed the work product of all of the Parties and may not be construed against any Party by reason of its drafting or preparation. Accordingly, any rule of law or any legal decision that would require interpretation of any ambiguities in this Agreement against any Party that drafted or prepared it is of no application and is expressly waived by each of the Parties, and any controversy over interpretations of this Agreement shall be decided without regard to events of drafting or preparation.

11.    This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware without giving effect to the choice of law principles of such state. Each Party irrevocably and unconditionally consents to the exclusive institution and resolution of any action, suit or proceeding of any kind or nature with respect to or arising out of this Agreement brought by any Party in the Chancery Court of the State of Delaware and the appellate courts thereof. Each Party irrevocably and unconditionally waives any objection to the laying of venue of any action, suit or proceeding arising out of this agreement in such court, and further irrevocably and unconditionally waives and agrees not to plead or claim in any such court that any such action, suit or proceeding brought in any such court has been brought in an inconvenient forum. The Parties agree that a final judgment in any such dispute shall be conclusive and may be enforced in other jurisdictions by suits on the judgment or in any other manner provided by law. The Parties agree that mailing of process or other papers in connection with any such action or proceeding in the manner provided in paragraph 12 or in such other manner as may be permitted by applicable law, shall be valid and sufficient service thereof. Each of the Parties, after consulting or having had the opportunity to consult with counsel, knowingly, voluntarily and intentionally waives any right that such Party may have to a trial by jury in any litigation based upon or arising out of this Agreement or any related instrument or agreement, or any of the transactions contemplated thereby, or any course of conduct, dealing, statements (whether oral or written), or actions of any of them. No Party shall seek to consolidate, by counterclaim or otherwise, any action in which a jury trial has been waived with any other action in which a jury trial cannot be or has not been waived.

12.    All notices, consents, requests, instructions, approvals and other communications provided for in this Agreement, and all legal process in regard hereto, shall be in writing and shall be deemed validly given, made or served when delivered in person, by electronic mail, by overnight courier or two (2) business days after being sent by registered or certified mail (postage prepaid, return receipt requested) as follows:

If to the Company to:

QEP Resources, Inc.

1050 17th Street

Denver, CO 80265

Attention: Christopher K. Woosley, Esq.

Email: chris.woosley@qepres.com

8

with a copy (which shall not constitute notice) to:

Wachtell, Lipton, Rosen & Katz

51 West 52^nd Street

New York, NY 10019-6119

Attention: David A. Katz, Esq.

Email: dakatz@wlrk.com

and

Latham & Watkins LLP

885 Third Avenue

New York, NY 10022-4834

Attention: Mark D. Gerstein, Esq.

Email: mark.gerstein@lw.com

If to Elliott:

Elliott Management Corporation

40 West 57 Street

New York, NY 10019-4001

Attention: Andrew Taylor

Email: ataylor@elliottmgmt.com

with a copy (which shall not constitute notice) to:

Olshan Frome Wolosky LLP

1325 Avenue of the Americas

New York, NY 10019

Attention: Steve Wolosky, Esq. and Andrew Freedman, Esq.

Email: swolosky@olshanlaw.com and afreedman@olshanlaw.com

At any time, any Party may, by notice given in accordance with this paragraph 12 to the other Party, provide updated information for notices hereunder

13.    This Agreement may be executed in two counterparts, each of which shall be deemed to be an original, but all of which shall constitute the same agreement and shall become a binding agreement when a counterpart has been signed by each party and delivered to the other party, thereby constituting the entire agreement among the parties pertaining to the subject matter hereof. Signatures of the parties transmitted by facsimile, PDF, jpeg, .gif, .bmp or other electronic file shall be deemed to be their original signatures for all purposes and the exchange of copies of this Agreement and of signature pages by facsimile transmission, PDF or other electronic file shall constitute effective execution and delivery of this Agreement as to the parties.

[Signature page follows]

9

Please confirm your agreement with the foregoing by signing and returning this agreement to the undersigned, whereupon this Agreement shall become a binding agreement between Elliott and the Company.

	Very truly yours,
	QEP RESOURCES, INC.
By:	/s/ Charles B. Stanley
Name:	Charles B. Stanley
Title:	Chairman, President and Chief Executive Officer

Accepted and agreed

as of the date first written above:

Elliott Management Corporation

By: /s/ Elliot Greenberg

Name: Elliot Greenberg

Title: Vice President

10

EXHIBIT A

[Final Version of Press Release]

11

EX-12.1

Exhibit 12.1

QEP Resources, Inc.

Ratio of Earnings to Fixed Charges

	Year Ended December 31,
	2017					2016					2015					2014					2013
Earnings	(in millions)
Income from continuing operations before income taxes and adjustment for income or loss from equity investees	$	(42.9	)			$	(1,953.2	)			$	(243.0	)			$	(642.0	)			$	112.2
Add (deduct):
Fixed charges	141.0					146.2					148.3					175.6					167.8
Distributed income from equity investees	—					—					0.1					0.3					0.2
Capitalized interest	—					—					—					—					(2.0		)
Total earnings	$	98.1				$	(1,807.0	)			$	(94.6	)			$	(466.1	)			$	278.2
Fixed Charges
Interest expense	$	137.8				$	143.2				$	145.6				$	172.9				$	163.3
Capitalized interest	—					—					—					—					2.0
Estimate of the interest within rental expense	3.2					3.0					2.7					2.7					2.5
Total Fixed Charges	$	141.0				$	146.2				$	148.3				$	175.6				$	167.8
Ratio of Earnings to Fixed Charges	—			(1	)	—			(2	)	—			(3	)	—			(4	)	1.7

____________________________

⁽¹⁾  Due to a loss for the year ended December 31, 2017, the ratio coverage was less than 1:1. QEP required additional earnings of $42.9 million for the year ended December 31, 2017, to achieve a ratio of 1:1.

⁽²⁾  Due to a loss for the year ended December 31, 2016, the ratio coverage was less than 1:1. QEP required additional earnings of $1,953.2 million for the year ended December 31, 2016, to achieve a ratio of 1:1.

⁽³⁾  Due to a loss for the year ended December 31, 2015, the ratio coverage was less than 1:1. QEP required additional earnings of $243.0 million for the year ended December 31, 2015, to achieve a ratio of 1:1.

⁽⁴⁾  Due to a loss for the year ended December 31, 2014, the ratio coverage was less than 1:1. QEP required additional earnings of $642.0 million for the year ended December 31, 2014, to achieve a ratio of 1:1.

EX-21.1

Exhibit 21.1

QEP Resources, Inc.

Subsidiaries of the Company

Name	State of Organization
QEP Energy Company(1)	Delaware
QEP Marketing Company(1)	Utah
QEP Field Services Company(1)	Delaware
Clear Creek Storage Company, LLC(2)	Utah
Permian Gathering, LLC(2)	Delaware
QEP Oil & Gas Company(2)	Delaware
Wyoming Peak Land Company, LLC(3)	Wyoming
Haynesville Gathering LP(4)	Delaware
Sakakawea Area Spill Response LLC(5)	Delaware

____________________________

⁽¹⁾  100% owned by QEP Resources, Inc.

⁽²⁾  100% owned by QEP Marketing Company

⁽³⁾  100% owned by QEP Energy Company

⁽⁴⁾  99% owned by QEP Oil and Gas Company and 1% owned by QEP Marketing Company

⁽⁵⁾  6% owned by QEP Resources, Inc.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-202686) and on Form S-8 (No. 333-167726 and No. 333-167727) of QEP Resources, Inc. of our report dated February 28, 2018, relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Denver, Colorado

February 28, 2018

EX-23.2

Exhibit 23.2

FAX (303) 623-4258

621 SEVENTEENTH STREET     SUITE 1550     DENVER, COLORADO 80293      TELEPHONE (303) 623-9147

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

As independent petroleum engineers, we hereby consent to the reference of our appraisal reports relating to the proved gas and oil reserves of QEP Energy Company in the Annual Report on Form 10-K of QEP Resources, Inc. as of the years ended December 31, 2013, 2014, 2015, 2016 and 2017 incorporated herein by reference into Registration Statement Nos. 333-202686 on Form S-3, 333-167726 and 333-167727 on Form S-8.

	/s/ Ryder Scott Company, L.P.
	Ryder Scott Company, L.P.
Denver, Colorado
February 28, 2018

EX-23.3

Exhibit 23.3

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY VOAD

SUITE 800 EAST

DALLAS, TEXAS 75244

February 28, 2018

QEP Resources, Inc.

1050 17^th Street, Suite 800

Denver, Colorado 80265

Ladies and Gentlemen:

As independent petroleum engineers, we hereby consent to the reference to our report entitled "Report as of December 31, 2015 on Reserves and Revenue owned by QEP Energy Company," relating to the proved oil, natural gas liquids, and gas reserves of QEP Energy Company for the year ended December 31, 2015, in the year-end 2017 Annual Report on Form 10-K of QEP Resources, Inc. incorporated herein by reference into Registration Statement Nos. 333-202686 on Form S-3 and Registration Statement Nos. 333-167726 and 333-167727 on Form S-8.

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGolyer and MacNaughton

Texas Registered Engineering Firm F-716

EX-24

Exhibit 24

POWER OF ATTORNEY

We, the undersigned directors of QEP Resources, Inc., hereby severally constitute Charles B. Stanley and Richard J. Doleshek, and each of them acting alone, our true and lawful attorneys, with full power to them and each of them to sign for us, and in our names in the capacities indicated below, the Annual Report on Form 10-K for 2017 and any and all amendments to be filed with the Securities and Exchange Commission by QEP Resources, Inc., hereby ratifying and confirming our signatures as they may be signed by the attorneys appointed herein to the Annual Report on Form 10-K for 2017 and any and all amendments to such Report.

Witness our hands on the respective dates set forth below.

Signature	Title	Date
/s/ Charles B. Stanley	Chairman of the Board	2/28/2018
Charles B. Stanley	President and Chief Executive Officer
/s/ David A. Trice	Director	2/28/2018
David A. Trice
/s/ Julie A. Dill	Director	2/28/2018
Julie A. Dill
/s/ M. W. Scoggins	Director	2/28/2018
M. W. Scoggins
/s/ Mary Shafer Malicki	Director	2/28/2018
Mary Shafer Malicki
/s/ Michael J. Minarovic	Director	2/28/2018
Michael J. Minarovic
/s/ Phillip S. Baker, Jr.	Director	2/28/2018
Phillips S. Baker, Jr.
/s/ Robert F. Heinemann	Director	2/28/2018
Robert F. Heinemann
/s/ William L. Thacker, III	Director	2/28/2018
William L. Thacker, III

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Charles B. Stanley, certify that:

1. I have reviewed this report of QEP Resources, Inc. on Form 10-K for the period ended December 31, 2017;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 28, 2018

/s/ Charles B. Stanley

Charles B. Stanley

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Richard J. Doleshek, certify that:

1. I have reviewed this report of QEP Resources, Inc. on Form 10-K for the period ended December 31, 2017;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 28, 2018

/s/ Richard J. Doleshek

Richard J. Doleshek

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of QEP Resources, Inc. (the Company) on Form 10-K for the period ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the Report), Charles B. Stanley, Chairman, President and Chief Executive Officer of the Company, and Richard J. Doleshek, Executive Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	QEP RESOURCES, INC.
February 28, 2018
	/s/ Charles B. Stanley
	Charles B. Stanley
	Chairman, President and Chief Executive Officer
February 28, 2018
	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President and Chief Financial Officer

EX-99.1

QEP Energy Company    

January 19, 2018

Page 1

Exhibit 99.1

FAX (303) 623-4258

621 SEVENTEENTH STREET     SUITE 1550     DENVER, COLORADO 80293      TELEPHONE (303) 623-9147

January 19, 2018

QEP Energy Company

1050 Seventeenth Street, Suite 800

Denver, Colorado 80265

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of QEP Energy Company (QEP) as of December 31, 2017. The subject properties are located in the states of Colorado, Louisiana, Montana, New Mexico, North Dakota, Oklahoma, Texas, Utah and Wyoming. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 19, 2018 and presented herein, was prepared for public disclosure by QEP in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of QEP as of December 31, 2017.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2017, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

QEP Energy Company    

January 19, 2018

Page 2

SEC PARAMETERS Estimated Net Reserves and Income Data Certain Leasehold and Royalty Interests of QEP Energy Company As of December 31, 2017
	Proved
	Developed						Total Proved
	Producing		Non-producing		Undeveloped
Net Remaining Reserves
Oil/Condensate - Mbbl	108,714		7,306		204,508		320,528
Plant Products - Mbbl	26,374		1,500		37,371		65,245
Gas - MMcf vc	523,275		132,221		1,138,150		1,793,646
Income Data ($M)
Future Gross Revenue	$	6,849,160	$	753,892	$	13,309,878	$	20,912,930
Deductions	3,754,955		509,056		8,420,308		12,684,319
Future Net Income (FNI)	$	3,094,205	$	244,836	$	4,889,570	$	8,228,611
Discounted FNI @ 10%	$	2,058,314	$	121,375	$	1,574,147	$	3,753,836

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (Mbbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of QEP. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. Other deductions are variable lease operating expenses. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Future net income does not include depreciation, depletion and amortization affects nor any impairment conditions. Liquid hydrocarbon reserves account for approximately 76 percent and gas reserves account for the remaining 24 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

QEP Energy Company    

January 19, 2018

Page 3

	Discounted Future Net Income ($M) As of December 31, 2017
Discount Rate Percent	Total Proved
5	$5,314,882
9	$4,002,353
15	$2,812,887
20	$2,199,279

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulations Part 210.4-10(a). An abridged version of the SEC reservesdefinitions from 210.4-10(a) entitled "Petroleum Reserves Definitions" is included as an attachment tothis report.

The various proved reserve status categories are defined under the attachment entitled "Petroleum Reserves Status Definitions and Guidelines" in this report. The proved developed non-producingreserves included herein consist of wells that are waiting on completion, behind pipe, shut-in,or temporarily abandoned.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. In general, gas consumed in operations was excluded from reserves.  However, in some cases, produced gas consumed in operations was included in reserves when the volumes replaced fuel purchases.

Reserves are "estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations." All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At QEP's request, this report addresses only the proved reserves attributable to the properties evaluated herein.

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". The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a "high degree of confidence that the quantities will be recovered."

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that"as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease."Moreover, estimates of proved reserves may be revised as a result of future operations, effects ofregulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reservesincluded in this report are estimates only and should not be construed as being exact quantities, and ifrecovered, the revenues therefrom, and the actual costs related thereto, could be more or less than theestimated amounts.

QEP Energy Company    

January 19, 2018

Page 4

QEP's operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenureand leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmentalprotection, marketing and pricing policies, royalties, various taxes and levies including income tax andare subject to change from time to time. Such changes in governmental regulations and policies maycause volumes of proved reserves actually recovered and amounts of proved income actually receivedto differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which QEP owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission's Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the "quantities actually recovered are much more likely than not to be achieved." The SEC states that "probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered." The SEC states that "possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves." All quantities of reserves within the same reservecategory must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods and analogy. All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis which utilized extrapolations of historical production data available through December 2017 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by QEP and were considered sufficient for the purpose thereof.

Approximately 100 percent of the proved developed non-producing and undeveloped reserves included herein were estimated by analogy. The data utilized from the analogues were considered sufficient for the purpose thereof.

QEP Energy Company    

January 19, 2018

Page 5

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

QEP has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by QEP with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by QEP. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The provedreserves included herein were determined in conformance with the United States Securities andExchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including allreferences to Regulation S-X and Regulation S-K, referred to herein collectively as the "SECRegulations." In our opinion, the proved reserves presented in this report comply with the definitions,guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our 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.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by QEP. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

QEP Energy Company    

January 19, 2018

Page 6

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the "as of date" of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

QEP furnished us with the above mentioned average prices in effect on December 31, 2017. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the "benchmark prices" and "price reference" used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as "differentials." The differentials used in the preparation ofthis report were furnished to us by QEP.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the "average realized prices." The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$51.34/bbl	$49.11/bbl
	NGLs	WTI Cushing	$51.34/bbl	$15.99/bbl
	Gas	Henry Hub	$2.98/MMBTU	$2.92/Mcf

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations

Costs

Operating costs for the leases and wells in this report were furnished to us by QEP and are based on the operating expense reports of QEP and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells.

The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by QEP. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by QEP and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by QEP were accepted without independent verification.

QEP Energy Company    

January 19, 2018

Page 7

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with QEP's plans to develop these reserves as of December 31, 2017. The implementation of QEP's development plans as presented to us and incorporated herein is subject to the approval process adopted by QEP's management. As the result of our inquiries during the course of preparing this report, QEP has informed us that the development activities included herein have been subjected to and received the internal approvals required by QEP's management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to QEP. Additionally, QEP has informed us that they are not aware of any legal, regulatory or political obstacles that wouldsignificantly alter their plans. While these plans could change from those under existing economicconditions as of December 31, 2017, such changes were, in accordance with rules adopted by theSEC, omitted from consideration in making this evaluation.

Current costs used by QEP were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer's license or a registered or certified professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to QEP. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by QEP.

QEP makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, QEP has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Forms S-3 and/or S-8 of QEP of the references to our name as well as to the references to our third party report for QEP, which appears inthe December 31, 2017 annual report on Form 10-K of QEP. Our written consent for such use isincluded as a separate exhibit to the filings made with the SEC by QEP.

QEP Energy Company    

January 19, 2018

Page 8

We have provided QEP with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by QEP and the original signed report letter, the original signed report letter shall control and supersede the digital version.

QEP Energy Company    

January 19, 2018

Page 9

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/James L. Baird

James L. Baird, P.E.

Colorado License No 41521

Managing Senior Vice President

[Seal]

/s/ Richard J. Marshall

Richard J. Marshall, P.E.

Colorado License No. 23260

Vice President

[Seal]

JLB-RJM (DCR)/pl

QEP Energy Company    

January 19, 2018

Page 10

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Richard J. Marshall was the primary technical person responsible for overseeing the estimate of the future net reserves and income.

Mr. Marshall, an employee of Ryder Scott Company, L.P. (Ryder Scott) beginning in 1981, is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies. Before joining Ryder Scott, Mr. Marshall served in a number of engineering positions with Texaco, Phillips Petroleum, and others. For more information regarding Mr. Marshall's geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Marshall earned a B.S. in Geology from the University of Missouri in 1974 and a M.S. in Geological Engineering from the University of Missouri at Rolla in 1976. Mr. Marshall is a registered Professional Engineer in the State of Colorado. He is a member of the Society of Petroleum Engineers, Wyoming Geological Association, Rocky Mountain Association of Geologists and the Society of Petroleum Evaluation Engineers.

Based on Mr. Marshall’s educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Marshall has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Jan. 31, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	QEP RESOURCES, INC.
Entity Central Index Key	0001108827
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		240,968,931
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Entity Public Float			$ 2,429,606,369

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
REVENUES
Oil sales	$ 939.4	$ 769.1	$ 834.2
Gas sales	494.0	417.1	468.5
NGL sales	111.9	83.5	80.0
Other revenues	15.0	6.2	15.1
Purchased oil and gas sales	62.6	101.2	620.8
Total Revenues	1,622.9	1,377.1	2,018.6
OPERATING EXPENSES
Purchased oil and gas expense	64.3	105.5	626.8
Lease operating expense	294.8	224.7	238.8
Transportation and processing costs	245.3	289.2	291.3
Gathering and other expense	7.3	5.0	5.8
General and administrative	153.5	196.5	168.0
Production and property taxes	114.3	94.8	117.6
Depreciation, depletion and amortization	754.5	871.1	881.1
Exploration expenses	22.0	1.7	2.7
Impairment	78.9	1,194.3	55.6
Total Operating Expenses	1,734.9	2,982.8	2,387.7
Net gain (loss) from asset sales	213.5	5.0	4.6
OPERATING INCOME (LOSS)	101.5	(1,600.7)	(364.5)
Realized and unrealized gains (losses) on derivative contracts (Note 6)	24.5	(233.0)	277.2
Interest and other income (expense)	1.6	23.7	(10.1)
Loss from early extinguishment of debt	(32.7)	0.0	0.0
Interest expense	(137.8)	(143.2)	(145.6)
INCOME (LOSS) BEFORE INCOME TAXES	(42.9)	(1,953.2)	(243.0)
Income tax (provision) benefit	312.2	708.2	93.6
NET INCOME (LOSS)	$ 269.3	$ (1,245.0)	$ (149.4)
Earnings (loss) per common share
Basic	$ 1.12	$ (5.62)	$ (0.85)
Diluted	$ 1.12	$ (5.62)	$ (0.85)
Weighted-average common shares outstanding
Used in basic calculation	240.6	221.7	176.6
Used in diluted calculation	240.6	221.7	176.6
Dividends per common share	$ 0.00	$ 0.00	$ 0.08

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ 269.3	$ (1,245.0)	$ (149.4)
Other comprehensive income, net of tax:
Future tax effective rate change(1)	[1]	(3.8)	0.0	0.0
Pension and other postretirement plans adjustments:
Current period prior service cost(2)	[2]	(2.4)	0.0	0.6
Current period net actuarial (gain) loss(3)	[3]	5.8	(5.6)	(0.5)
Amortization of prior service cost(4)	[4]	0.5	0.8	8.2
Amortization of net actuarial (gain) loss(5)	[5]	0.3	0.5	0.3
Net curtailment and settlement cost incurred(6)	[6]	0.4	0.0	4.5
Other comprehensive income (loss)		5.6	(4.3)	11.9
Comprehensive income (loss)		$ 274.9	$ (1,249.3)	$ (137.5)

[1] The new tax legislation changed the federal corporate income tax rate from 35% to 21% starting in 2018. The rate change caused the Company to revalue its deferred tax liabilities and assets using the lower rate.

[2] Presented net of income tax expense of $0.8 million for the year ended December 31, 2017 and net of income tax benefit of $0.3 million for the year ended December 31, 2015.

[3] Presented net of income tax expense of $1.8 million for the year ended December 31, 2017 and net of income tax benefit of $3.3 million and $0.3 million for the years ended December 31, 2016 and 2015, respectively.

[4] Presented net of income tax expense of $0.2 million, $0.5 million, and $4.9 million for the years ended December 31, 2017, 2016, and 2015, respectively.

[5] Presented net of income tax expense of $0.1 million, $0.3 million, and $0.2 million for the years ended December 31, 2017, 2016, and 2015, respectively.

[6] Presented net of income tax expense of $0.1 million and $2.6 million for the years ended December 31, 2017 and 2015, respectively.

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension and other postretirement plans adjustments:
Current period prior service cost, tax	[1]	$ 0.8	$ 0.0	$ (0.3)
Current period net actuarial (gain) loss, tax	[2]	(1.8)	3.3	0.3
Amortization of prior service cost, tax	[3]	(0.2)	(0.5)	(4.9)
Amortization of net actuarial (gain) loss, tax	[4]	(0.1)	(0.3)	(0.2)
Net curtailment and settlement cost incurred, tax	[5]	$ 0.1	$ 0.0	$ (2.6)

[1] Presented net of income tax expense of $0.8 million for the year ended December 31, 2017 and net of income tax benefit of $0.3 million for the year ended December 31, 2015.

[2] Presented net of income tax expense of $1.8 million for the year ended December 31, 2017 and net of income tax benefit of $3.3 million and $0.3 million for the years ended December 31, 2016 and 2015, respectively.

[3] Presented net of income tax expense of $0.2 million, $0.5 million, and $4.9 million for the years ended December 31, 2017, 2016, and 2015, respectively.

[4] Presented net of income tax expense of $0.1 million, $0.3 million, and $0.2 million for the years ended December 31, 2017, 2016, and 2015, respectively.

[5] Presented net of income tax expense of $0.1 million and $2.6 million for the years ended December 31, 2017 and 2015, respectively.

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 0.0	$ 443.8
Accounts receivable, net	142.1	155.7
Income tax receivable	4.9	18.6
Fair value of derivative contracts	3.4	0.0
Hydrocarbon inventories, at lower of average cost or net realizable value	3.6	10.4
Prepaid expenses	10.7	11.4
Other current assets	0.7	0.2
Total Current Assets	165.4	640.1
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	12,470.9	14,232.5
Unproved properties	1,095.8	871.5
Gathering and other	319.7	301.8
Materials and supplies	37.8	32.7
Total Property, Plant and Equipment	13,924.2	15,438.5
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,642.9	8,797.7
Gathering and other	124.3	101.8
Total Accumulated Depreciation, Depletion and Amortization	6,767.2	8,899.5
Net Property, Plant and Equipment	7,157.0	6,539.0
Fair value of derivative contracts	0.1	0.0
Other noncurrent assets	72.3	66.3
TOTAL ASSETS	7,394.8	7,245.4
Current Liabilities
Checks outstanding in excess of cash balances	44.0	12.3
Accounts payable and accrued expenses	372.1	269.7
Production and property taxes	31.6	30.1
Interest payable	26.0	32.9
Fair value of derivative contracts	103.6	169.8
Total Current Liabilities	577.3	514.8
Long-term debt	2,160.8	2,020.9
Deferred income taxes	518.0	825.9
Asset retirement obligations	206.6	225.8
Fair value of derivative contracts	31.8	32.0
Other long-term liabilities	102.4	123.3
Commitments and Contingencies (Note 9)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 243.0 million and 240.7 million shares issued, respectively	2.4	2.4
Treasury stock - 2.0 million and 1.1 million shares, respectively	(34.2)	(22.9)
Additional paid-in capital	1,398.2	1,366.6
Retained earnings	2,442.6	2,173.3
Accumulated other comprehensive income (loss)	(11.1)	(16.7)
Total Common Shareholders' Equity	3,797.9	3,502.7
TOTAL LIABILITIES AND EQUITY	$ 7,394.8	$ 7,245.4

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares shares in Millions	Dec. 31, 2017	Dec. 31, 2016
EQUITY
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	500.0	500.0
Common stock, shares issued (in shares)	243.0	240.7
Treasury stock (in shares)	2.0	1.1

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CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Millions, $ in Millions	Total	Common Stock, Value [Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Other Comprehensive Income (Loss) [Member]	Stockholders' Equity, Total [Member]
Balance at Dec. 31, 2014		$ 1.8	$ (25.4)	$ 535.3	$ 3,587.9	$ (24.3)	$ 4,075.3
Shares at Dec. 31, 2014		176.2
Treasury shares at Dec. 31, 2014			(0.8)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 149.4	$ 0.0	$ 0.0	0.0	(149.4)	0.0	(149.4)
Net income (loss), shares		0.0	0.0
Dividends		0.0	0.0
Dividends		$ 0.0	$ 0.0	0.0	(14.1)	0.0	(14.1)
Share-based compensation		$ 0.0	$ 10.8	19.5	(6.1)	0.0	24.2
Share-based compensation, shares		1.1	0.3
Change in pension and postretirement liability, net of tax, shares		0.0	0.0
Change in pension and postretirement liability, net of tax		$ 0.0	$ 0.0	0.0	0.0	11.9	11.9
Shares at Dec. 31, 2015		177.3
Treasury shares at Dec. 31, 2015			(0.5)
Balance at Dec. 31, 2015		$ 1.8	$ (14.6)	554.8	3,418.3	(12.4)	3,947.9
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 1,245.0	$ 0.0	$ 0.0	0.0	(1,245.0)	0.0	(1,245.0)
Net income (loss), shares		0.0	0.0
Equity issuance, net of offering costs, shares		61.0	0.0
Equity issuance, net of offering costs		$ 0.6	$ 0.0	780.8	0.0	0.0	(781.4)
Share-based compensation		$ 0.0	$ (8.3)	31.0	0.0	0.0	22.7
Share-based compensation, shares		2.4	(0.6)
Change in pension and postretirement liability, net of tax, shares		0.0	0.0
Change in pension and postretirement liability, net of tax		$ 0.0	$ 0.0	0.0	0.0	(4.3)	(4.3)
Shares at Dec. 31, 2016		240.7
Treasury shares at Dec. 31, 2016	(1.1)		(1.1)
Balance at Dec. 31, 2016	$ 3,502.7	$ 2.4	$ (22.9)	1,366.6	2,173.3	(16.7)	3,502.7
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ (269.3)	$ 0.0	$ 0.0	0.0	269.3	0.0	269.3
Net income (loss), shares		0.0	0.0
Share-based compensation		$ 0.0	$ (11.3)	31.6	0.0	0.0	20.3
Share-based compensation, shares		2.3	(0.9)
Change in pension and postretirement liability, net of tax, shares		0.0	0.0
Change in pension and postretirement liability, net of tax		$ 0.0	$ 0.0	0.0	0.0	5.6	5.6
Shares at Dec. 31, 2017		243.0
Treasury shares at Dec. 31, 2017	(2.0)		(2.0)
Balance at Dec. 31, 2017		$ 2.4	$ (34.2)	$ 1,398.2	$ 2,442.6	$ (11.1)	$ 3,797.9

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
OPERATING ACTIVITIES
Net income (loss)	$ 269.3	$ (1,245.0)	$ (149.4)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	754.5	871.1	881.1
Deferred income taxes	(314.8)	(651.3)	25.3
Impairment	78.9	1,194.3	55.6
Dry hole exploratory well expense	21.3	0.0	0.0
Share-based compensation	22.4	35.6	34.7
Pension curtailment loss	0.0	0.0	11.2
Amortization of debt issuance costs and discounts	6.2	6.4	6.2
Bargain purchase gain from acquisitions	0.4	(22.6)	0.0
Net (gain) loss from asset sales	(213.5)	(5.0)	(4.6)
Loss from early extinguishment of debt	32.7	0.0	0.0
Unrealized (gains) losses on marketable securities	(2.9)	(1.4)	0.2
Unrealized (gains) losses on derivative contracts	(40.0)	367.0	183.7
Other non-cash activity	(9.4)	0.0	0.0
Accounts receivable	(2.0)	95.3	124.6
Hydrocarbon inventories	(1.1)	8.7	15.5
Prepaid expenses	(0.2)	18.5	16.7
Accounts payable and accrued expenses	3.5	(50.3)	(34.5)
Federal income taxes receivable	13.7	68.7	(619.4)
Other	(20.6)	(26.3)	(65.6)
Net Cash Provided by (Used in) Operating Activities	598.4	663.7	481.3
INVESTING ACTIVITIES
Property acquisitions	(815.2)	(639.0)	(98.3)
Property, plant and equipment, including exploratory well expense	(1,159.6)	(569.1)	(1,141.1)
Proceeds from disposition of assets	806.8	29.0	21.8
Net Cash Provided by (Used in) Investing Activities	(1,168.0)	(1,179.1)	(1,217.6)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	31.7	(17.5)	(24.9)
Long-term debt issued	500.0	0.0	0.0
Long-term debt issuance costs paid	(14.4)	0.0	(2.6)
Long-term debt extinguishment costs paid	(28.1)	0.0	0.0
Long-term debt repaid	(445.6)	(176.8)	0.0
Proceeds from credit facility	492.0	0.0	0.0
Repayments of credit facility	(403.0)	0.0	0.0
Treasury stock repurchases	(6.8)	(4.1)	(2.7)
Other capital contributions	0.0	0.0	(0.2)
Dividends paid	0.0	0.0	(14.1)
Proceeds from issuance of common stock, net	0.0	781.4	0.0
Excess tax (provision) benefit on share-based compensation	0.0	(0.1)	3.2
Net Cash Provided by (Used in) Financing Activities	125.8	583.1	(47.7)
Change in cash and cash equivalents	(443.8)	67.7	(784.0)
Beginning cash and cash equivalents	443.8	376.1	1,160.1
Ending cash and cash equivalents	$ 0.0	$ 443.8	$ 376.1

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Nature of Business

QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Northern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".

Principles of Consolidation

The Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Consolidated Financial Statements were prepared in accordance with GAAP and with the instructions for annual reports on Form 10-K and Regulations S-X. All significant intercompany accounts and transactions have been eliminated in consolidation.

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

Termination of Marketing Agreements

Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and Haynesville Gathering. As a result, QEP Energy directly markets its own oil, gas and NGL production. While QEP continues to act as an agent for the sale of oil, gas and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had prior to 2016.

In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP had one reportable segment effective January 1, 2016. The Company has recast its financial statements for historical periods to reflect the impact of the termination of marketing agreements to show its financial results without segments.

Reclassifications

Certain prior period amounts on the Consolidated Statements of Operations, Consolidated Balance Sheets and Consolidated Statements of Cash Flows have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's net income (loss), earnings (loss) per share, cash flows, current assets or retained earnings previously reported.

Use of Estimates

The preparation of the Consolidated Financial Statements and Notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management's estimates and assumptions is the estimate of proved oil, gas and NGL reserves, which are used in the calculation of depreciation, depletion and amortization rates of its oil and gas properties, impairment of proved properties and asset retirement obligations. Changes in estimated quantities of its reserves could impact the Company's reported financial results as well as disclosures regarding the quantities and value of proved oil and gas reserves. Other items subject to estimates and assumptions include the carrying amount of property, plant and equipment, assigning fair value and allocating purchase price in connection with business combinations, valuation allowances for receivables, income taxes, valuation of derivatives instruments, accrued liabilities, accrued revenue and related receivables and obligations related to employee benefits, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Risks and Uncertainties

The Company's revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil, gas and NGL, which are affected by many factors outside of QEP's control, including changes in market supply and demand. Changes in market supply and demand are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. Field-level prices received for QEP's oil and gas production have historically been volatile and may be subject to significant fluctuations in the future. The Company's derivative contracts serve to mitigate in part the effect of this price volatility on the Company's cash flows, and the Company has derivative contracts in place for a portion of its expected future oil and gas production. Refer to Note 6 – Derivative Contracts for the Company's open oil and gas commodity derivative contracts.

Revenue Recognition

QEP recognizes revenue from oil and gas producing activities in the period that services are provided or products are delivered. Revenues associated with the sale of oil, gas and NGL are accounted for using the sales method, whereby revenue is recognized when these commodities are sold to purchasers. Revenues include estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators. An imbalance liability is recorded to the extent that QEP has sold volumes in excess of its share of remaining reserves in an underlying property.

QEP also purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. QEP recognizes revenue from these resale activities when title transfers to the customer.

Cash and Cash Equivalents and Restricted Cash

Cash equivalents consist principally of highly liquid investments in securities with original maturities of three months or less made through commercial bank accounts that result in available funds the next business day.

As of December 31, 2017, QEP had no unrestricted cash and restricted cash of $23.4 million. As of December 31, 2016, QEP had unrestricted cash of $443.8 million and restricted cash of $21.6 million. QEP's restricted cash is primarily cash deposited into an escrow account related to a title dispute between third parties in the Williston Basin and is included in "Other noncurrent assets" on the Consolidated Balance Sheets.

Supplemental cash flow information is shown in the table below:

	Year Ended December 31,
	2017			2016			2015
Supplemental Disclosures	(in millions)
Cash paid for interest, net of capitalized interest	$	134.9		$	139.1		$	139.4
Cash paid (refund received) for income taxes, net	$	(0.3	)	$	(123.5	)	$	487.8
Non-cash investing activities
Change in capital expenditure accrual balance	$	60.2		$	(32.8	)	$	(129.2	)

Accounts Receivable

Accounts receivable consists mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company's oil and gas receivables are collected and bad debts are minimal. However, if commodity prices remain low for an extended period of time, the Company could incur increased levels of bad debt expense. Recovery of bad debt associated with accounts receivable for the year ended December 31, 2017 was $1.0 million. Bad debt expense associated with accounts receivable for the years ended December 31, 2016 and 2015, was $1.8 million, and $0.5 million, respectively. Bad debt recovery or expense is included in "General and administrative" expense on the Consolidated Statements of Operations. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. The allowance for bad debt expenses was $1.6 million at December 31, 2017, and $4.8 million at December 31, 2016.

Property, Plant and Equipment

Property, plant and equipment balances are stated at historical cost. Material and supplies inventories are valued at the lower of cost or net realizable value. Maintenance and repair costs are expensed as incurred. Significant accounting policies for our property, plant and equipment are as follows:

Successful Efforts Accounting for Oil and Gas Operations

The Company follows the successful efforts method of accounting for oil and gas property acquisitions, exploration, development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected. Capitalized costs of unproved properties are reclassified to proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.

Capitalized Exploratory Well Costs

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

Depreciation, Depletion and Amortization (DD&A)

Capitalized proved leasehold costs are depleted on a field-by-field basis using the unit-of-production method and the estimated proved oil and gas reserves. Capitalized costs of exploratory wells that have found proved oil and gas reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves for a successful effort field. The Company capitalizes an estimate of the fair value of future abandonment costs.

DD&A for the Company's remaining properties is generally based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets using the straight-line method. The estimated useful lives of those assets depreciated under the straight-line basis generally range as follows:

Buildings	10 to 30 years
Leasehold improvements	3 to 10 years
Service, transportation and field service equipment	3 to 7 years
Furniture and office equipment	3 to 7 years

Impairment of Long-Lived Assets

Proved oil and gas properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value. Triggering events could include, but are not limited to, a reduction of oil, gas and NGL reserves caused by mechanical problems, faster-than-expected decline of production, lease ownership issues, and declines in oil, gas and NGL prices. If impairment is indicated, fair value is estimated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices, operating costs and estimates of proved, probable and possible reserves. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors.

Unproved properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.

During the year ended December 31, 2017, QEP recorded impairment charges of $78.9 million, of which $38.1 million was related to proved properties due to lower future gas prices, $29.0 million was primarily related to unproved leasehold acreage in the Central Basin Platform (Refer to Note 3 – Capitalized Exploratory Well Costs for additional information), $6.5 million was related to impairment of an underground gas storage facility and $5.3 million was related to the impairment of goodwill. Of the $38.1 million impairment of proved properties, $37.1 million related to the Other Northern area and $1.0 million related to Louisiana properties.

During the year ended December 31, 2016, QEP recorded impairment charges of $1,194.3 million, of which $1,172.7 million was related to proved properties due to lower future oil and gas prices, $17.9 million was related to expiring leaseholds on unproved properties and $3.7 million was related to the impairment of goodwill. Of the $1,172.7 million impairment of proved properties, $1,164.0 million related to Pinedale properties, $4.7 million related to Uinta Basin properties, $3.4 million related to the Other Northern area and $0.6 million related to QEP's remaining Other Southern properties.

During the year ended December 31, 2015, QEP recorded impairment charges of $55.6 million, of which $39.3 million was related to proved properties due to lower future oil and gas prices, $2.0 million was related to expiring leaseholds on unproved properties and $14.3 million was related to the impairment of goodwill. Of the $39.3 million impairment on proved properties, $20.2 million related to QEP's remaining Other Southern properties, $18.4 million related Other Northern properties, and $0.7 million related to Permian Basin properties.

Asset Retirement Obligations

QEP is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. ARO associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement costs, is depreciated over the useful life of the asset. ARO are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded to both the ARO liability and the long-lived asset. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. Refer to Note 4 – Asset Retirement Obligations for additional information.

Goodwill

Goodwill represents the excess of the amount paid over the fair value of assets acquired in a business combination and is not subject to amortization. During the year ended December 31, 2017, QEP early adopted ASU 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment. Under the new guidance QEP performs an annual goodwill impairment test by comparing the fair value of a reporting unit with its carry amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. QEP determines the fair value of its reporting units in which goodwill is allocated using the income approach in which the fair value is estimated based on the value of expected future cash flows. Key assumptions used in the cash flow model include estimated quantities of oil, gas and NGL reserves, including both proved reserves and risk-adjusted unproved reserves, and including probable and possible reserves; estimates of market prices considering forward commodity price curves as of the measurement date; estimates of revenue and operating costs over a multi-year period; and estimates of capital costs.

During the year ended December 31, 2017, QEP recorded $5.3 million of goodwill, which related to an acquisition in the first quarter of 2017. During the fourth quarter of 2017, QEP performed an annual impairment test over goodwill as described above, which resulted in a full write down of goodwill of $5.3 million.

During the years ended December 31, 2016 and 2015, QEP recorded $3.7 million and $14.3 million, respectively, of goodwill. Annual impairment tests over goodwill at year end December 31, 2016 and 2015 resulted in a full write down of $3.7 million and $14.3 million, respectively.

Litigation and Other Contingencies

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Consolidated Financial Statements. The amount of ultimate loss may differ from these estimates. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Refer to Note 9 – Commitments and Contingencies for additional information.

QEP accrues material losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.

Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. QEP uses commodity derivative instruments, typically fixed-price swaps and costless collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. QEP does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. Additionally, QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates.

These derivative contracts are recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Consolidated Statements of Operations in the month of settlement and are also marked-to-market monthly. Refer to Note 6 – Derivative Contracts for additional information.

Credit Risk

Management believes that its credit review procedures, loss reserves, cash deposits and investments, and collection procedures have adequately provided for usual and customary credit-related losses. Exposure to credit risk may be affected by extended periods of low commodity prices, as well as the concentration of customers in certain regions due to changes in economic or other conditions. Customers include commercial and industrial enterprises and financial institutions that may react differently to changing conditions.

The Company utilizes various processes to monitor and evaluate its credit risk exposure, which include closely monitoring current market conditions and counterparty credit fundamentals, including public credit ratings, where available. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals, and is aggregated across all lines of business, including derivatives, physical exposure and short-term cash investments. To further manage the level of credit risk, the Company requests credit support and, in some cases, requests parental guarantees, letters of credit or prepayment from companies with perceived higher credit risk. Loss reserves are periodically reviewed for adequacy and may be established on a specific case basis. The Company also has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

The Company enters into International Swap Dealers Association Master Agreements (ISDA Agreements) with each of its derivative counterparties prior to executing derivative contracts. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or counterparty to a derivative contract. The Company routinely monitors and manages its exposure to counterparty risk related to derivative contracts by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties public credit ratings, and avoiding concentration of credit exposure by transacting with multiple counterparties. The Company's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings.

The Company's five largest customers accounted for 59%, 48%, and 30% of QEP's revenues for the years ended December 31, 2017, 2016 and 2015, respectively. During the year ended December 31, 2017, Shell Trading Company, Occidental Energy Marketing, Andeavor Logistics LP, BP Energy Company and Plains Marketing LP accounted for 14%, 13%, 13%, 10% and 10%, respectively, of QEP's total revenues. During the year ended December 31, 2016, Shell Trading Company, BP Energy Company and Valero Marketing & Supply Company accounted for 14%, 10% and 10%, respectively, of QEP's total revenues. During the year ended December 31, 2015, no customer accounted for 10% or more of QEP's total revenues. 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.

Income Taxes

The amount of income taxes recorded by QEP requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. QEP has recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. Deferred income taxes are provided for the temporary differences arising between the book and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods.

ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company's recorded income tax benefits will be fully realized, except as noted below. As of December 31, 2017, the Company had a valuation allowance of $56.8 million against the state net operating loss deferred tax asset because management does not forecast future income in Oklahoma and Louisiana to offset net operating losses before they expire. All federal income tax returns prior to 2017 have been examined by the Internal Revenue Service and are closed. Income tax returns for 2017 have not yet been filed. Most state tax returns for 2014 and subsequent years remain subject to examination.

The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more-likely-than-not to be sustained upon examination by the relevant taxing authorities. Our policy is to recognize any interest earned on income tax refunds in "Interest and other income (expense)" on the Consolidated Statements of Operations, any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statements of Operations and to recognize any penalties related to uncertain tax positions in "General and administrative" expense on the Consolidated Statements of Operations. As of December 31, 2017 and 2016, QEP had $19.0 million and $15.6 million of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which was included within "Other long-term liabilities" on the Consolidated Balance Sheets. During the year ended December 31, 2017, the Company incurred $0.7 million of estimated interest expense related to uncertain tax positions. During the year ended December 31, 2016, the Company incurred $0.7 million of estimated interest expense and $0.6 million of estimated penalties related to uncertain tax positions. During the year ended December 31, 2015, the Company incurred $0.5 million of estimated interest expense and $2.2 million of estimated penalties related to uncertain tax positions.

On December 22, 2017 the Tax Cuts and Jobs Act (H.R.1) (Tax Legislation) was signed into law, which resulted in significant changes to U.S. federal income tax law. QEP expects that these changes will positively impact QEP's future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate of 21% compared to 35%. The Tax Legislation also repeals the corporate alternative minimum tax (AMT). Several provisions of the new tax law such as limitations on the deductibility of interest expense and certain executive compensation and the inability to use Section 1031 like-kind exchanges for assets such as machinery and equipment could apply to QEP; however, we do not believe that they will materially impact QEP's financial statements. The impact of the Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made and actions the Company may take as a result of the Tax Legislation.  Additionally, guidance issued by the relevant regulatory authorities regarding the Tax Legislation may materially impact QEP's financial statements. The Company will continue to analyze the Tax Legislation to determine the full impact of the new law, on the Company's consolidated financial statements and operations.

Treasury Stock

We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders' equity in the Consolidated Balance Sheets. QEP acquires treasury stock from stock forfeitures and withholdings and uses the acquired treasury stock for stock option exercises and certain stock grants to employees; refer to Note 10 – Share-Based Compensation for additional information.

Earnings (Loss) Per Share

Basic earnings (loss) per share (EPS) are computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP's unvested restricted share awards are included in weighted-average basic common shares outstanding because, once the shares are granted, the restricted share awards are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted share awards are eligible to receive dividends.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings (loss) per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) per common share. For the years ended December 31, 2017 and 2015, there were no anti-dilutive shares. For the year ended December 31, 2016, there were 0.1 million shares not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss from continuing operations.

The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation:

	December 31,
	2017	2016	2015
	(in millions)
Weighted-average basic common shares outstanding	240.6	221.7	176.6
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—
Average diluted common shares outstanding	240.6	221.7	176.6

Share-Based Compensation

QEP issues stock options, restricted share awards and restricted share units to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. The grant date fair value for restricted share awards is determined based on the closing bid price of the Company's common stock on the grant date. Share-based compensation cost for restricted share units is equal to its fair value as of the end of the period and is classified as a liability. QEP uses an accelerated method in recognizing share-based compensation costs for stock options and restricted share awards with graded-vesting periods. Stock options held by employees generally vest in three equal, annual installments and primarily have a term of seven years. Restricted share awards and restricted share units vest in equal installments over a specified number of years after the grant date with the majority vesting in three years. Non-vested restricted share awards have voting and dividend rights; however, sale or transfer is restricted. Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified unfunded deferred compensation plan at the time of vesting. The Company also awards performance share units under its CIP that are generally paid out in cash depending upon the Company's total shareholder return compared to a group of its peers over a three-year period. Share-based compensation cost for the performance share units is equal to its fair value as of the end of the period and is classified as a liability. For additional information, refer to Note 10 – Share-Based Compensation for additional information.

Pension and Other Postretirement Benefits

QEP maintains closed, defined-benefit pension and other postretirement benefit plans, including both a qualified and a supplemental plan. QEP also provides certain health care and life insurance benefits for certain retired QEP employees. Determination of the benefit obligations for QEP's defined-benefit pension and other postretirement benefit plans impacts the recorded amounts for such obligations on the Consolidated Balance Sheets and the amount of benefit expense recorded to the Consolidated Statements of Operations.

QEP measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement benefit plans include the discount rate, the expected rate of return on plan assets (for funded pension plans) and the rate of future compensation increases. Other assumptions involve demographic factors such as retirement, mortality and turnover. QEP evaluates and updates its actuarial assumptions at least annually. QEP recognizes a pension curtailment immediately when there is a significant reduction in, or an elimination of, defined-benefit accruals for present employees' future services. Refer to Note 11 – Employee Benefits for additional information.

Comprehensive Income (Loss)

Comprehensive income (loss) is the sum of net income (loss) as reported in the Consolidated Statements of Operations and changes in the components of other comprehensive income. Other comprehensive income (loss) includes certain items that are recorded directly to equity and classified as accumulated other comprehensive income (AOCI), which includes changes in the underfunded portion of the Company's defined-benefit pension and other postretirement benefits plans and changes in deferred income taxes on such amounts. These transactions do not represent the culmination of the earnings process but result from periodically adjusting historical balances to fair value.

Recent Accounting Developments

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In addition, new and enhanced disclosures will be required. The amendment is effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 15, 2016. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The Company does not expect net income (loss) or cash flows to be materially impacted by the new standard; however, the Company expects that a portion of its transportation and processing costs will be netted within revenue under the new standard. In addition, the Company will have expanded disclosure requirements, as a result of the adoption of the ASU. The Company has selected the modified retrospective method and will adopt this guidance on the effective date of January 1, 2018.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-06, Derivatives and hedging (Topic 815): Contingent put and call options in debt instruments, which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The amendment was effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption was permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment was effective prospectively for reporting periods beginning after December 15, 2016, and early adoption was permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of certain cash receipts and cash payments , which intends to reduce the diversity in practice in how certain transactions are classified in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the fourth quarter of 2017 and the adoption of this standard did not have a material impact on the Company's Consolidated Financial Statements.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the definition of a business, which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of businesses. The amendment will be effective prospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the fourth quarter of 2017 and the adoption of this standard did not have a material impact on the Company's Consolidated Financial Statements; however, this standard may impact the determination of whether future acquisitions are accounted for as a business combination or an asset acquisition.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment, which eliminates the requirement to calculate implied fair value of goodwill to measure the goodwill impairment charge. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, which changes how employers of a defined benefit plan present net periodic benefit cost in the statements of operations. The amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and recast the years ended December 31, 2016 and 2015. The adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements. Refer to Note 11 – Employee Benefits for additional information regarding the Company's pension and other postretirement plans.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Acquisitions and divestitures [Text Block]

2017 Permian Basin Acquisition

In the fourth quarter of 2017, QEP acquired additional oil and gas properties in the Permian Basin for an aggregate purchase price of $720.7 million, subject to post-closing purchase price adjustments (the 2017 Permian Basin Acquisition). The 2017 Permian Basin Acquisition consists of approximately 15,100 acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. QEP structured the transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded the purchase price with the proceeds from the Pinedale Divestiture. In accordance with the early adoption of ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the definition of a business in the fourth quarter of 2017, the 2017 Permian Basin Acquisition meets the definition of an asset acquisition because substantially all of the total fair value acquired relates to undeveloped leaseholds which do not have outputs. In addition, QEP has made offers to various persons who own additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the original purchase. If all offers are accepted, the aggregate purchase price is not expected to exceed $50.0 million.

2016 Permian Basin Acquisition

In October 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $591.0 million (the 2016 Permian Basin Acquisition). The 2016 Permian Basin Acquisition consists of approximately 9,600 net acres in Martin County, Texas, which are primarily held by production from existing vertical wells. The 2016 Permian Basin Acquisition was funded with cash on hand, which included proceeds from an equity offering in June 2016.

The 2016 Permian Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included significant proved properties. QEP allocated the cost of the 2016 Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $80.2 million and a net income of $221.4 million were generated from the acquired properties for the year ended December 31, 2017. Revenues of $3.8 million and a net loss of $0.7 million were generated from the acquired properties from October 19, 2016 to December 31, 2016. The revenue and net income (loss) are included in QEP's Consolidated Statements of Operations. During the year ended December 31, 2016, QEP incurred acquisition-related costs of $2.3 million, which are included in "General and administrative" expense on the Consolidated Statements of Operations. In conjunction with the 2016 Permian Basin Acquisition, the Company recorded a $17.8 million bargain purchase gain. The acquisition resulted in a bargain purchase gain primarily as a result of an increase in future oil prices from the execution of the purchase and sale agreement to the closing date of the acquisition. The bargain purchase gain is reported on the Consolidated Statements of Operations within "Interest and other income (expense)".

The following table presents a summary of the Company's purchase accounting entries (in millions) as of December 31, 2017:

Consideration:
Total consideration	$	591.0
Amounts recognized for fair value of assets acquired and liabilities assumed:
Proved properties	$	406.2
Unproved properties	214.2
Asset retirement obligations	(11.6		)
Bargain purchase gain	(17.8		)
Total fair value	$	591.0

The following unaudited, pro forma results of operations are provided for the year ended December 31, 2016. Pro forma results are not provided for the year ended December 31, 2017, because the 2016 Permian Basin Acquisition occurred during the fourth quarter of 2016; and therefore, the results are included in QEP's results of operations for the year ended December 31, 2017. The supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the periods presented, or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the year ended December 31, 2016, the acquired properties' historical results of operations and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting, and quantifying, the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the 2016 Permian Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.

	Year ended December 31,
	2016
	Actual			Pro forma
	(in millions, except per share amounts)
Revenues	$	1,377.1		$	1,392.5
Net income (loss)	$	(1,245.0	)	$	(1,246.8	)
Earnings (loss) per common share
Basic	$	(5.62	)	$	(5.62	)
Diluted	$	(5.62	)	$	(5.62	)

Other Acquisitions

In addition to the 2017 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2017, which primarily included undeveloped leasehold acreage, producing wells and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million, subject to customary post-closing purchase price adjustments. In conjunction with the acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired.

In addition to the 2016 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2016, primarily in the Permian and Williston basins, for an aggregate purchase price of $54.6 million, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage. In conjunction with the acquisitions, the Company recorded $3.7 million of goodwill, which was subsequently impaired, and a $4.4 million bargain purchase gain. The bargain purchase gain is reported on the Consolidated Statements of Operations within "Interest and other income (expense)".

During the year ended December 31, 2015, QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for a total purchase price of $98.3 million, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage. In conjunction with the acquisitions, the Company recorded $14.3 million of goodwill, which was subsequently impaired.

Pinedale Divestiture

In September 2017, QEP sold its Pinedale assets (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to post-closing purchase price adjustments, and recorded a pre-tax gain on sale of $180.4 million which was recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations. As part of the purchase and sale agreement, at the request of the buyer, QEP agreed to enter into derivative contracts covering a portion of Pinedale's future production. Those derivative contracts were novated to the buyer at closing. In addition, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. The fair value of the deficiency charges was measured utilizing an internally developed cash flow model discounted at QEP's weighted average cost of debt. Given the unobservable nature of the inputs, the fair value calculation associated with the deficiency charges is considered Level 3 within the fair value hierarchy. As of December 31, 2017, the liability associated with estimated future payments for this commitment was $30.6 million, of which $27.4 million is reported on the Consolidated Balance Sheets within "Accounts payable and accrued expenses" and $3.2 million is reported on the Consolidated Balance Sheets within "Other long-term liabilities".

QEP accounted for revenues and expenses related to Pinedale, including the pre-tax gain on sale of $180.4 million, during the years ended December 31, 2017, 2016 and 2015, as income on the Consolidated Statements of Operations because the sale of the Pinedale assets did not cause a strategic shift for the Company and as a result, did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The Pinedale Divestiture did, however, represent the sale of an individually significant component. For the year ended December 31, 2017, QEP recorded net income before income taxes related to Pinedale, prior to the divestiture, of $251.0 million, which includes the pre-tax gain on sale of $180.4 million. For the year ended December 31, 2016, QEP recorded a net loss before income taxes of $1,152.7 million. The net loss before income taxes was primarily due to an impairment on proved properties of $1,164.0 million recognized in 2016 as a result of a decrease in expected future gas prices. For the year ended December 31, 2015, QEP recorded net loss before income taxes of $45.6 million related to Pinedale.

Other Divestitures

In addition to the Pinedale Divestiture, during the year ended December 31, 2017, QEP also sold its Central Basin Platform assets (Central Basin Platform Divestiture) and received net cash proceeds of $3.5 million. Refer to Note 3 – Capitalized Exploratory Well Costs for more information. In addition, QEP received net cash proceeds of $85.1 million and recorded a pre-tax gain on sale of $33.1 million, primarily related to the sale of properties in the Other Northern area.

During the year ended December 31, 2016, QEP sold its interest in certain non-core properties, primarily in the Other Southern area for aggregate proceeds of $29.0 million and recorded a pre-tax gain on sale of $8.6 million.

During the year ended December 31, 2015, QEP sold its interest in certain non-core properties in the Other Southern area for aggregate proceeds of $31.7 million, of which $21.8 million was cash and $9.9 million of accounts receivable and recorded a pre-tax gain on sale of $21.0 million. During the year ended December 31, 2016, QEP recorded a pre-tax loss of sale of $0.9 million, due to post-closing purchase price adjustments from the sale of such properties.

These gains and losses are reported on the Consolidated Statements of Operations within "Net gain (loss) from asset sales".

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Capitalized Exploratory Well Costs

12 Months Ended

Dec. 31, 2017

Capitalized Exploratory Well Costs [Abstract]

Suspended Well Costs Disclosure [Text Block]

Net changes in capitalized exploratory well costs are presented in the table below.

	Capitalized Exploratory Well Costs
	2017			2016			2015
	(in millions)
Balance at January 1,	$	14.2		$	2.6		$	12.6
Additions to capitalized exploratory well costs	10.7			11.7			6.0
Reclassifications to proved properties	(3.6		)	—			(16.0		)
Capitalized exploratory well costs charged to expense	(21.3		)	(0.1		)	—
Balance at December 31,	$	—		$	14.2		$	2.6

The balance at December 31, 2016 and 2015 represents the amount of capitalized exploratory well costs that are pending the determination of proved reserves.

During the years ended December 31, 2017 and 2016, QEP's exploratory well activity was related to the Central Basin Platform exploration project in the Permian Basin targeting the Woodford Formation. QEP completed a second exploratory well related to this project in the first half of 2017. During the year ended December 31, 2017, based on the performance of the two exploratory wells that were drilled and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project and would seek to monetize the assets. QEP charged $21.3 million of exploratory well costs to exploration expense. In conjunction with the expensing of the exploratory well costs, QEP charged $28.3 million of the associated unproved leasehold acreage in the Central Basin Platform to impairment expense during the year ended December 31, 2017. QEP wrote down the Central Basin Platform assets to their fair market value of $3.6 million and reclassified the assets to proved properties. During the fourth quarter of 2017, QEP closed on the Central Basin Platform Divestiture for net cash proceeds of $3.5 million.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

QEP records ARO associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $214.1 million and $231.6 million ARO liability as of December 31, 2017 and 2016, respectively, $7.5 million and $5.8 million, respectively, was included as a liability in "Accounts payable and accrued expenses" on the Consolidated Balance Sheets.

The following is a reconciliation of the changes in the Company's ARO for the periods specified below:

	Asset Retirement Obligations
	2017			2016
	(in millions)
ARO liability at January 1,	$	231.6		$	206.8
Accretion	7.7			8.9
Additions(1)	23.5			17.0
Revisions	8.5			6.5
Liabilities related to assets sold(2)	(34.9		)	—
Liabilities settled	(22.3		)	(7.6		)
ARO liability at December 31,	$	214.1		$	231.6

___________________________

⁽¹⁾  Additions for the year ended December 31, 2017, include $14.2 million related to the 2017 Permian Basin Acquisition and additions for the year ended December 31, 2016, include $11.6 million related to the 2016 Permian Basin Acquisition (refer to Note 2 – Acquisitions and Divestitures for more information).

⁽²⁾  Liabilities related to assets sold for the year ended December 31, 2017, include $34.9 million related to the Pinedale Divestiture (refer to Note 2 – Acquisitions and Divestitures for more information).

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Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures. This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 also establishes a fair value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability.

QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (refer to Note 6 – Derivative Contracts for additional information) is based on market prices posted on the respective commodity exchange on the last trading day of the reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels at the end of the reporting period.

Certain of the Company's commodity derivative instruments are valued using industry standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also incorporates nonperformance risk for counterparties and for QEP. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with the counterparty exists.

The fair value of financial assets and liabilities at December 31, 2017 and 2016, is shown in the table below:

	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
	December 31, 2017
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	20.6	$	—	$	(17.2	)	$	3.4
Fair value of derivative contracts – long-term	—		2.3		—		(2.2		)	0.1
Total financial assets	$	—	$	22.9	$	—	$	(19.4	)	$	3.5
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	120.8	$	—	$	(17.2	)	$	103.6
Fair value of derivative contracts – long-term	—		34.0		—		(2.2		)	31.8
Total financial liabilities	$	—	$	154.8	$	—	$	(19.4	)	$	135.4
	December 31, 2016
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	—	$	—	$	—		$	—
Fair value of derivative contracts – long-term	—		—		—		—			—
Total financial assets	$	—	$	—	$	—	$	—		$	—
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	169.8	$	—	$	—		$	169.8
Fair value of derivative contracts – long-term	—		32.0		—		—			32.0
Total financial liabilities	$	—	$	201.8	$	—	$	—		$	201.8

____________________________

⁽¹⁾  The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Consolidated Balance Sheets for the contracts that contain netting provisions. Refer to Note 6 – Derivative Contracts for additional information regarding the Company's derivative contracts.

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K:

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	December 31, 2017				December 31, 2016
Financial Assets	(in millions)
Cash and cash equivalents	$	—	$	—	$	443.8	$	443.8
Financial Liabilities
Checks outstanding in excess of cash balances	$	44.0	$	44.0	$	12.3	$	12.3
Long-term debt	$	2,160.8	$	2,256.2	$	2,020.9	$	2,104.3

The carrying amounts of cash and cash equivalents and checks outstanding in excess of cash balances approximate fair value. The fair value of fixed-rate long-term debt is based on the trading levels and dollar prices for the Company's debt at the end of the year. The carrying amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt was set for periods of one month.

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO include plugging costs and reserve lives. A reconciliation of the Company's ARO is presented in Note 4 – Asset Retirement Obligations.

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a nonrecurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. During the years ended December 31, 2017 and 2016, the Company recorded impairments of certain proved oil and gas properties of $38.1 million and $1,172.7 million, respectively, resulting in a reduction of the associated carrying value to fair value. The fair value of the property was measured utilizing the income approach and utilizing inputs which are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. Given the unobservable nature of the inputs, fair value calculations associated with proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. Refer to Note 1 – Summary of Significant Accounting Policies for additional information on impairment of oil and gas properties.

Acquisitions of proved and unproved properties are also measured at fair value on a nonrecurring basis. The Company utilizes a discounted cash flow model to estimate the fair value of acquired property as of the acquisition date which utilizes the following inputs to estimate future net cash flows: (i) estimated quantities of oil, gas and NGL reserves; (ii) estimates of future commodity prices; and (iii) estimated production rates, future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the acquired properties is considered Level 3 within the fair value hierarchy. Refer to Note 2 – Acquisitions and Divestitures for additional information on the fair value of acquired properties.

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Derivative Contracts

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production, but generally, QEP enters into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. In addition, QEP may enter into commodity derivative contracts on a portion of its storage transactions. QEP does not enter into commodity derivative contracts for speculative purposes.

QEP uses commodity derivative instruments known as fixed-price swaps or costless collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma or oil price swaps that use ICE Brent oil prices as the reference price. Gas price derivative instruments are typically structured as fixed-price swaps or costless collars at NYMEX Henry Hub or regional price indices. QEP also enters into oil and gas basis swaps to achieve a fixed-price swap for a portion of its oil and gas sales at prices that reference specific regional index prices.

QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. QEP's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties public credit ratings and avoiding the concentration of credit exposure by transacting with multiple counterparties. The Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

Derivative Contracts – Production

The following table presents QEP's volumes and average prices for its commodity derivative swap contracts as of December 31, 2017:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2018	NYMEX WTI	16.8	$	52.48
2019	NYMEX WTI	8.0	$	51.78
Gas sales		(MMBtu)	($/MMBtu)
2018 (Full Year)	NYMEX HH	109.5	$	2.99
2018 (July through December)	NYMEX HH	1.8	$	3.01
2019	NYMEX HH	36.5	$	2.88

QEP uses oil and gas basis swaps, combined with NYMEX WTI and NYMEX HH fixed price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table presents details of QEP's oil and gas basis swaps as of December 31, 2017:

Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2018 (Full Year)	NYMEX WTI	Argus WTI Midland	7.3	$	(1.06	)
2018 (July through December)	NYMEX WTI	Argus WTI Midland	0.9	$	(0.71	)
2019	NYMEX WTI	Argus WTI Midland	4.0	$	(0.80	)
Gas sales			(MMBtu)	($/MMBtu)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)

Derivative Contracts – Gas Storage

QEP enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage. The following table presents QEP's volumes and average prices for its gas storage commodity derivative swap contracts as of December 31, 2017:

Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2018	SWAP	IFNPCR	0.6	$	3.06

QEP Derivative Financial Statement Presentation

The following table identifies the Consolidated Balance Sheets location of QEP's outstanding derivative contracts on a gross contract basis as opposed to the net contract basis presentation on the Consolidated Balance Sheets and the related fair values at the balance sheet dates:

		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
		December 31,
	Balance Sheet line item	2017		2016		2017		2016
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	20.6	$	—	$	120.8	$	169.8
Long-term:
Commodity	Fair value of derivative contracts	2.3		—		34.0		32.0
Total derivative instruments		$	22.9	$	—	$	154.8	$	201.8

The effects of the change in fair value and settlement of QEP's derivative contracts recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Consolidated Statements of Operations are summarized in the following table:

Derivative contracts not designated as cash flow hedges	Year Ended December 31,
	2017			2016			2015
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	6.8		$	86.3		$	353.7
Gas derivative contracts	(22.3		)	44.8			103.4
Gas Storage
Gas derivative contracts	—			2.9			3.8
Realized gains (losses) on commodity derivative contracts	(15.5		)	134.0			460.9
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(66.2		)	(217.2		)	(244.9		)
Gas derivative contracts	133.6			(145.4		)	62.0
Gas Storage
Gas derivative contracts	2.5			(4.4		)	(0.8		)
Unrealized gains (losses) on commodity derivative contracts	69.9			(367.0		)	(183.7		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts	$	54.4		$	(233.0	)	$	277.2
Derivatives associated with the Pinedale Divestiture(1)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	(1.3	)	$	—		$	—
Gas derivative contracts	(23.5		)	—			—
NGL derivative contracts	(5.1		)	—			—
Unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture	$	(29.9	)	$	—		$	—
Total realized and unrealized gains (losses) on commodity derivative contracts	$	24.5		$	(233.0	)	$	277.2

_______________________

⁽¹⁾  The unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 2 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations.

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Restructuring Costs

12 Months Ended

Dec. 31, 2017

Restructuring and Related Activities [Abstract]

Restructuring Costs

In April 2016, the Company streamlined its organizational structure, resulting in a reduction of approximately 6% of its total workforce. The total costs related to the 2016 restructuring were approximately $1.9 million and were related to one-time termination benefits. During the year ended December 31, 2016, restructuring costs of $1.9 million were incurred and paid related to the 2016 restructuring. The Company did not incur additional costs related to the 2016 restructuring in 2017.

During 2015, QEP had multiple restructuring events, including the closure of its Tulsa office, which occurred in the third quarter of 2015. The total costs related to the 2015 restructuring events were approximately $8.3 million, of which approximately $5.3 million was related to one-time termination benefits and approximately $3.0 million was related to relocation of certain employees. During the year ended December 31, 2016, restructuring costs of $0.6 million were incurred and paid related to the Tulsa office closure, all of which were related to the relocation of certain employees. The Company did not incur additional costs related to the closure of its Tulsa office.

All restructuring costs were recorded within "General and administrative" expense on the Consolidated Statements of Operations.

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Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Debt

As of the indicated dates, the principal amount of QEP's debt consisted of the following:

	December 31,
	2017			2016
	(in millions)
Revolving Credit Facility due 2022	$	89.0		$	—
6.80% Senior Notes due 2018(1)	—			134.0
6.80% Senior Notes due 2020(1)	51.7			136.0
6.875% Senior Notes due 2021(1)	397.6			625.0
5.375% Senior Notes due 2022	500.0			500.0
5.25% Senior Notes due 2023	650.0			650.0
5.625% Senior Notes due 2026(1)	500.0			—
Less: unamortized discount and unamortized debt issuance costs	(27.5		)	(24.1		)
Total long-term debt outstanding	$	2,160.8		$	2,020.9

_______________________

⁽¹⁾  During the quarter ended December 31, 2017, the Company issued $500.0 million of 5.625% Senior Notes due in 2026. The Company used the majority of the proceeds from the offering to redeem all of its outstanding 6.80% Senior Notes due in 2018 and fund tender offers for $84.3 million of 6.80% Senior Notes due in 2020 and $227.4 million of its outstanding 6.875% Senior Notes due in 2021. The Company recorded a $32.7 million loss from early extinguishment of debt related to the redemption and tender offers.

Of the total debt outstanding on December 31, 2017, the 6.80% Senior Notes due March 1, 2020, the 6.875% Senior Notes due March 1, 2021 and the 5.375% Senior Notes due October 1, 2022, will mature within the next five years. In addition, the revolving credit facility matures on September 1, 2022.

Credit Facility

In November 2017, QEP entered into the Seventh Amendment to its Credit Agreement, which, among other things, reduced the aggregate principal amount of commitments to $1.25 billion and extended the maturity date, subject to satisfaction of certain conditions, to September 1, 2022. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The amended credit agreement contains financial covenants (that are defined in the credit agreement) that limit the amount of debt the Company can incur and may limit the amount available to be drawn under the credit facility including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarter ending December 31, 2017, 4.00 times commencing with the fiscal quarter ending March 31, 2018, through the fiscal quarter ending December 31, 2018, and 3.75 times thereafter, and (iii) during a ratings trigger period (as defined), a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2019, must exceed net funded debt by 1.40 times commencing on January 1, 2019, through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. The company is currently not subject to the present value coverage ratio. As of December 31, 2017 and 2016, QEP was in compliance with the covenants under the credit agreement.

During the year ended December 31, 2017, QEP's weighted-average interest rates on borrowings from its credit facility were 3.52%. As of December 31, 2017, QEP had $89.0 million of borrowings outstanding and $1.0 million in letters of credit outstanding under the credit facility. As of December 31, 2016, QEP had no borrowings outstanding and $2.8 million in letters of credit outstanding under the credit facility.

Senior Notes

At December 31, 2017, the Company had $2,099.3 million principal amount of senior notes outstanding with maturities ranging from March 2020 to March 2026 and coupons ranging from 5.25% to 6.875%. The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP's senior notes contain customary events of default and covenants that may limit QEP's ability to, among other things, place liens on its property or assets.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Contingencies

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Consolidated Financial Statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.

Legal proceedings are inherently unpredictable and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires judgment about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoing discovery and/or development of information important to the matter.

Litigation

Landowner Litigation – In October, 2017, the owners of certain surface and mineral interests in Martin and Andrews County, Texas filed suit against QEP, alleging QEP improperly used the surface of the properties and failed to correctly pay royalties, and are seeking money damages and a declaratory judgment that portions of the oil and gas leases covering the properties are no longer in effect. The Company continues to evaluate the allegations and its defenses. The Company is unable to make an estimate of the reasonably possible loss at this early stage.

Commitments

QEP has contracted for gathering, processing, firm transportation and storage services with various third parties. Market conditions, drilling activity and competition may prevent full utilization of the contractual capacity. In addition, QEP has contracts with third parties who provide drilling services. Annual payments and the corresponding years for gathering, processing, transportation, storage, drilling, and fractionation contracts are as follows (in millions):

Year	Amount
2018	$	95.6
2019	$	68.4
2020	$	54.9
2021	$	29.9
2022	$	28.3
After 2022	$	122.5

QEP rents office space throughout its scope of operations from third-party lessors. Rental expense from operating leases amounted to $9.6 million, $9.1 million, and $8.0 million during the years ended December 31, 2017, 2016 and 2015, respectively. Minimum future payments under the terms of long-term operating leases for the Company's primary office locations are as follows (in millions):

Year	Amount
2018	$	7.0
2019	$	7.2
2020	$	7.4
2021	$	7.4
2022	$	7.2
After 2022	$	4.8

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Share-Based Compensation

12 Months Ended

Dec. 31, 2017

Share-based Compensation [Abstract]

Share-Based Compensation

QEP issues stock options, restricted share awards and restricted share units under its LTSIP and awards performance share units under its CIP to certain officers, employees, and non-employee directors. QEP recognizes expense over the vesting periods for the stock options, restricted share awards, restricted share units and performance share units. There were 5.0 million shares available for future grants under the LTSIP at December 31, 2017.

Share-based compensation expense related to continuing operations is recognized within "General and administrative" expense on the Consolidated Statements of Operations and is summarized in the table below.

	Year Ended December 31,
	2017			2016		2015
	(in millions)
Stock options	$	2.3		$	2.3	$	2.9
Restricted share awards	24.6			23.7		25.6
Performance share units	(4.5		)	9.4		6.2
Restricted share units	—			0.2		—
Total share-based compensation expense	$	22.4		$	35.6	$	34.7

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of grant. Fair value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for calculating the value of options not traded on an exchange. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares. The Company expenses forfeitures of stock options as they occur.

The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:

	Stock Option Assumptions
	Year Ended December 31,
	2017			2016			2015
Weighted-average grant date fair value of awards granted during the period	$	6.44		$	3.77		$	6.82
Risk-free interest rate range	1.66% - 1.81%			0.99% - 1.15%			1.38% - 1.38%
Weighted-average risk-free interest rate	1.8		%	1.2		%	1.4		%
Expected price volatility range	43.82% - 46.70%			43.42% - 43.66%			36.8% - 36.8%
Weighted-average expected price volatility	43.9		%	43.4		%	36.8		%
Expected dividend yield	—		%	—		%	0.37		%
Expected term in years at the date of grant	4.5			4.5			4.5

Stock option transactions under the terms of the LTSIP are summarized below:

	Options Outstanding		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
			(per share)		(in years)	(in millions)
Outstanding at December 31, 2016	2,151,957		$	25.26
Granted	418,752		16.77
Forfeited	(14,172	)	15.33
Cancelled	(202,260	)	27.55
Outstanding at December 31, 2017	2,354,277		$	23.62	3.50	$	—
Options Exercisable at December 31, 2017	1,551,861		$	27.90	2.47	$	—
Unvested Options at December 31, 2017	802,416		$	15.33	5.48	$	—

During the years ended December 31, 2017 and 2016, there were no exercises of stock options. The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.1 million during the year ended December 31, 2015. There was no income tax impact for the year ended December 31, 2017. The Company realized an income tax benefit of $0.2 million for the year ended December 31, 2016 and $6.4 million of income tax expense for the year ended December 31, 2015. As of December 31, 2017, $1.6 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.04 years.

Restricted Share Awards

Restricted share award grants typically vest in equal installments over a three-year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The Company expenses forfeitures of restricted share awards as they occur. The total fair value of restricted share awards that vested during the years ended December 31, 2017, 2016 and 2015, was $18.4 million, $24.3 million and $22.7 million, respectively. There was no income tax impact for the year ended December 31, 2017 and 2016. The Company realized an income tax benefit of $3.2 million for the year ended December 31, 2015. The weighted-average grant date fair value of restricted share awards granted was $13.90 per share, $10.50 per share and $20.92 per share for the years ended December 31, 2017, 2016 and 2015, respectively. As of December 31, 2017, $19.2 million of unrecognized compensation cost related to restricted share awards granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 1.99 years.

Transactions involving restricted share awards under the terms of the LTSIP are summarized below:

	Restricted Share Awards Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2016	3,208,503		$	14.32
Granted	2,219,763		13.90
Vested	(1,392,043	)	16.53
Forfeited	(314,889	)	14.49
Unvested balance at December 31, 2017	3,721,334		$	13.23

Performance Share Units

The payouts for performance share units are dependent upon the Company's total shareholder return compared to a group of its peers over a three-year period. The awards are denominated in share units and have historically been paid in cash. Beginning with awards granted in 2015, the Company has the option to settle earned awards in cash or shares of common stock under the Company's LTSIP; however, as of December 31, 2017, the Company expects to settle all awards in cash. These awards are classified as liabilities and are included within "Other long-term liabilities" on the Consolidated Balance Sheets. As these awards are dependent upon the Company's total shareholder return and stock price, they are measured at fair value at the end of each reporting period. The Company paid $5.3 million, $2.8 million and $3.1 million for vested performance share units during the years ended December 31, 2017, 2016 and 2015, respectively. The weighted-average grant date fair value of the performance share units granted during the years ended December 31, 2017, 2016 and 2015, was $16.90, $10.16, and $21.69 per share, respectively. As of December 31, 2017, $1.2 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 1.89 years.

Transactions involving performance share units under the terms of the CIP are summarized below:

	Performance Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2016	1,027,280		$	17.24
Granted	405,014		16.90
Vested and paid	(215,439	)	31.63
Forfeited	(17,519	)	13.88
Unvested balance at December 31, 2017	1,199,336		$	14.59

Restricted Share Units

Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. These awards are ultimately delivered in cash. They are classified as liabilities in "Other long-term liabilities" on the Consolidated Balance Sheets and are measured at fair value at the end of each reporting period. The weighted-average grant date fair value of the restricted share units was $16.98 and $10.12 per share for the years ended December 31, 2017 and 2016, respectively. As of December 31, 2017, $0.1 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 1.03 years.

Transactions involving restricted share units under the terms of the LTSIP are summarized below:

	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2016	18,034		$	10.12
Granted	9,924		16.98
Vested	(6,012	)	10.12
Unvested balance at December 31, 2017	21,946		$	13.22

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Employee Benefits

12 Months Ended

Dec. 31, 2017

Compensation and Retirement Disclosure [Abstract]

Employee Benefits

Pension and other postretirement benefits

The Company provides pension and other postretirement benefits to certain employees through three retirement benefit plans: the QEP Resources, Inc. Retirement Plan (the Pension Plan), the Supplemental Executive Retirement Plan (the SERP), and a postretirement medical plan (the Medical Plan).

The Pension Plan is a closed, qualified, defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees, which, as of December 31, 2017, covers 30 active and suspended participants, or 5%, of QEP's active employees, and 184 participants that are retired or were terminated and vested. Pension Plan benefits are based on the employee's age at retirement, years of service as of the earlier of the participant's termination of employment or December 31, 2015, and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding termination of employment or, if earlier, December 31, 2015. During the year ended December 31, 2017, the Company made contributions of $4.0 million to the Pension Plan and expects to contribute approximately $4.0 million to the Pension Plan in 2018. Contributions to the Pension Plan increase plan assets. Due to the Pension Plan freeze on January 1, 2016, the Company began making additional contributions for eligible employees who were active participants in the Pension Plan on December 31, 2015 based on the eligible employee's age as of December 31, 2015. During the year ended December 31, 2017, QEP contributed $0.4 million for these employees.

As a result of the Company's 2014 divestitures and retirements in 2015, the number of active participants in the Pension Plan fell to 50 participants during the year ended December 31, 2015, which is the minimum number of active participants for a plan to meet the qualification requirements of the minimum participation rules under the Internal Revenue Code. In order to prevent disqualification, the Pension Plan was amended in June 2015 and was frozen effective January 1, 2016, such that employees do not earn additional defined benefits for future services except for purposes of determining eligibility for an early retirement benefit. This change resulted in a non-cash curtailment loss of $11.2 million recognized on the Consolidated Statements of Operations within "Interest and other income (expense)" expense during the year ended December 31, 2015. A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for present employees' future services.

The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. SERP benefits are based on the employee's age at retirement, years of service and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding the participant's termination of employment. During the year ended December 31, 2017, the Company made contributions of $2.0 million to its SERP and expects to contribute approximately $0.7 million in 2018. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and is closed to new participants effective January 1, 2016.

During the year ended December 31, 2017, the Company recognized a $0.7 million loss on curtailment related to the SERP in connection with the Pinedale Divestiture, which was recorded on the Consolidated Statements of Operations within "Net gain (loss) from asset sales".

The Medical Plan is a self-insured plan. It is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired QEP employees. The Medical Plan was originally provided only to employees hired by Questar Corporation before January 1, 1997. Of the 30 active, pension eligible employees, 17 are also eligible for the Medical Plan when they retire. As of December 31, 2017, 55 retirees are enrolled in the Medical Plan. The Company has capped its exposure to increasing medical costs by paying a fixed dollar monthly contribution toward these retiree benefits. The Company's contribution is prorated based on an employee's years of service at retirement; only those employees with 25 or more years of service receive the maximum company contribution. During the year ended December 31, 2017, the Company made contributions of $0.1 million and expects to contribute approximately $0.3 million of benefits in 2018. At December 31, 2017 and 2016, QEP's accumulated benefit obligation exceeded the fair value of its qualified retirement plan assets.

In February 2017, the Company changed the eligibility requirements for active employees eligible for the Medical Plan, as well as retirees currently enrolled. Effective July 1, 2017, the Company no longer offers the Medical Plan to a retiree and spouse that are both Medicare eligible. In addition, the Company no longer offers life insurance to individuals retiring on or after July 1, 2017.

In accordance with the early adoption of ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, the Company recast years ended December 31, 2016 and 2015 by recognizing service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of Operations. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations.

The accumulated benefit obligation for all defined-benefit pension plans was $128.7 million and $124.5 million at December 31, 2017 and 2016, respectively.

The following table sets forth changes in the benefit obligations and fair value of plan assets for the Company's Pension Plan, SERP and Medical Plan for the years ended December 31, 2017 and 2016, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2017 and 2016:

	Pension Plan and SERP benefits						Medical Plan benefits
	2017			2016			2017			2016
Change in benefit obligation	(in millions)
Benefit obligation at January 1,	$	129.2		$	120.3		$	5.4		$	5.2
Service cost	0.8			1.2			—			—
Interest cost	4.7			5.2			0.1			0.2
Curtailments	(0.3		)	—			—			—
Benefit payments	(6.9		)	(7.8		)	(0.1		)	(0.4		)
Plan amendments	—			—			(2.4		)	—
Actuarial loss (gain)	2.5			10.3			(0.1		)	0.4
Benefit obligation at December 31,	$	130.0		$	129.2		$	2.9		$	5.4
Change in plan assets
Fair value of plan assets at January 1,	$	86.1		$	79.3		$	—		$	—
Actual return on plan assets	15.3			7.4			—			—
Company contributions to the plan	6.0			7.2			0.1			0.4
Benefit payments	(6.9		)	(7.8		)	(0.1		)	(0.4		)
Fair value of plan assets at December 31,	100.5			86.1			—			—
Underfunded status (current and long-term)	$	(29.5	)	$	(43.1	)	$	(2.9	)	$	(5.4	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(1.5	)	$	(2.5	)	$	(0.2	)	$	(0.3	)
Other long-term liabilities	(27.9		)	(40.6		)	(2.6		)	(5.1		)
Total amount recognized in balance sheet	$	(29.4	)	$	(43.1	)	$	(2.8	)	$	(5.4	)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	15.0		$	23.5		$	(0.5	)	$	(0.4	)
Prior service cost	1.2			2.9			(1.2		)	1.0
Total amount recognized in AOCI	$	16.2		$	26.4		$	(1.7	)	$	0.6

The following table sets forth the Company's Pension Plan, SERP and Medical Plan cost and amounts recognized in other comprehensive income (before tax) for the respective years ended December 31:

	Pension Plan and SERP benefits									Medical Plan benefits
	2017			2016			2015			2017			2016			2015
Components of net periodic benefit cost	(in millions)
Service cost	$	0.8		$	1.2		$	2.1		$	—		$	—		$	—
Interest cost	4.7			5.2			4.9			0.1			0.2			0.2
Expected return on plan assets	(5.4		)	(5.6		)	(5.7		)	—			—			—
Curtailment loss	0.7			—			11.2			—			—			—
Settlements	0.2			—			—			—			—			—
Amortization of prior service costs	1.0			1.1			1.7			(0.3		)	0.2			0.2
Amortization of actuarial loss	0.5			0.8			0.5			(0.1		)	—			—
Periodic expense	$	2.5		$	2.7		$	14.7		$	(0.3	)	$	0.4		$	0.4
Components recognized in accumulated other comprehensive income
Current period prior service cost	$	(0.7	)	$	—		$	0.9		$	(2.5	)	$	—		$	—
Current period actuarial (gain) loss	(7.5		)	8.5			2.2			(0.1		)	0.4			(1.4		)
Amortization of prior service cost	(1.0		)	(1.1		)	(12.9		)	0.3			(0.2		)	(0.2		)
Amortization of actuarial gain (loss)	(0.5		)	(0.8		)	(0.5		)	0.1			—			—
Loss on curtailment in current period	(0.3		)	—			(7.1		)	—			—			—
Settlements	(0.2		)	—			—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	(10.2	)	$	6.6		$	(17.4	)	$	(2.2	)	$	0.2		$	(1.6	)

The Company recognizes service costs related to SERP and Medical Plan benefits on the Consolidated Statements of Operations within "General and administrative" expense. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized on the Consolidated Statements of Operations within "Interest and other income (expense)".

The estimated portion of net actuarial loss and net prior service cost for the Pension Plan and SERP that will be amortized from AOCI into net periodic benefit cost in 2018 is $1.9 million, which represents amortization of prior service cost recognized and actuarial losses. The estimated portion of net actuarial loss and net prior service cost for the Medical Plan that will be amortized from AOCI into net periodic benefit cost in 2018 is $0.3 million, which represents amortization of prior service cost recognized and actuarial gains. Amortization of prior service costs and actuarial gains or losses out of AOCI are recognized in the Consolidated Statements of Operations in "Interest and other income (expense)".

Following are the weighted-average assumptions (weighted by the plan level benefit obligation for pension benefits) used by the Company to calculate the Pension Plan, SERP and Medical Plan obligations at December 31, 2017 and 2016:

	Pension Plan and SERP benefits				Medical Plan benefits
	2017		2016		2017		2016
Discount rate	3.52	%	3.96	%	3.60	%	4.10	%
Rate of increase in compensation(1)	3.50	%	3.50	%	n/a		3.50	%

_______________________

⁽¹⁾   The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the years ended December 31, 2017 and 2016, the rate of increase in compensation only includes the SERP and Medical Plan.

The discount rate assumptions used by the Company represents an estimate of the interest rate at which the Pension Plan, SERP and Medical Plan obligations could effectively be settled on the measurement date.

Following are the weighted-average assumptions (weighted by the net period benefit cost for pension benefits) used by the Company in determining the net periodic Pension Plan, SERP and Medical Plan cost for the years ended December 31:

	Pension Plan and SERP benefits						Medical Plan benefits
	2017		2016		2015		2017		2016		2015
Discount rate	4.00	%	4.23	%	3.94	%	4.10	%	4.40	%	4.00	%
Expected long-term return on plan assets	6.00	%	6.50	%	6.75	%	n/a		n/a		n/a
Rate of increase in compensation(1)	3.50	%	4.00	%	4.00	%	3.50	%	4.00	%	4.00	%

_______________________

⁽¹⁾   The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the years ended December 31, 2017 and 2016, the rate of increase in compensation only includes the SERP and Medical Plan.

In selecting the assumption for expected long-term rate of return on assets, the Company considers the average rate of return expected on the funds to be invested to provide benefits. This includes considering the plan's asset allocation, historical returns on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the plan. No plan assets are expected to be returned to the Company in 2018. Historical health care cost trend rates are not applicable to the Company, because the Company's medical costs are capped at a fixed amount. As the Company's medical costs are capped at a fixed amount, the sensitivity to increases and decreases in the health-care inflation rate is not applicable.

Plan Assets

The Company's Employee Benefits Committee (EBC) oversees investment of qualified pension plan assets. The EBC uses a third-party asset manager to assist in setting targeted-policy ranges for the allocation of assets among various investment categories. The EBC allocates pension plan assets among broad asset categories and reviews the asset allocation at least annually. Asset allocation decisions consider risk and return, future-benefit requirements, participant growth and other expected cash flows. These characteristics affect the level, risk and expected growth of postretirement-benefit assets. The EBC uses asset-mix guidelines that include targets for each asset category, return objectives for each asset group and the desired level of diversification and liquidity. These guidelines may change from time to time based on the EBC's ongoing evaluation of each plan's risk tolerance. The EBC estimates an expected overall long-term rate of return on assets by weighting expected returns of each asset class by its targeted asset allocation percentage. Expected return estimates are developed from analysis of past performance and forecasts of long-term return expectations by third-parties. Responsibility for individual security selection rests with each investment manager, who is subject to guidelines specified by the EBC. The EBC sets performance objectives for each investment manager that are expected to be met over a three-year period or a complete market cycle, whichever is shorter. Performance and risk levels are regularly monitored to confirm policy compliance and that results are within expectations. Performance for each investment is measured relative to the appropriate index benchmark for its category. QEP securities may be considered for purchase at an investment manager's discretion, but within limitations prescribed by the Employee Retirement Income Security Act of 1974 (ERISA) and other laws. There was no direct investment in QEP shares for the periods disclosed. The majority of retirement-benefit assets were invested as follows:

Equity securities:Domestic equity assets were invested in a combination of index funds and actively managed products, with a diversification goal representative of the whole U.S. stock market. International equity securities consisted of developed and emerging market foreign equity assets that were invested in funds that hold a diversified portfolio of common stocks of corporations in developed and emerging foreign countries.

Debt securities: Investment grade intermediate-term debt assets are invested in funds holding a diversified portfolio of debt of governments, corporations and mortgage borrowers with average maturities of five to ten years and investment grade credit ratings. Investment grade long-term debt assets are invested in a diversified portfolio of debt of corporate and non-corporate issuers, with an average maturity of more than ten years and investment grade credit ratings. High yield and bank loan assets are held in funds holding a diversified portfolio of these instruments with an average maturity of five to seven years.

Although the actual allocation to cash and short-term investments is minimal (less than 5%), larger cash allocations may be held from time to time if deemed necessary for operational aspects of the retirement plan. Cash is invested in a high-quality, short-term temporary investment fund that purchases investment-grade quality short-term debt issued by governments and corporations.

The EBC made the decision to invest all of the retirement plan assets in commingled funds as these funds typically have lower expense ratios and are more tax efficient than mutual funds. These investments are public investment vehicles valued using the net asset value (NAV) as a practical expedient. The NAV is based on the underlying assets owned by the fund excluding transaction costs and minus liabilities, which can be traced back to observable asset values. No assets held by the Pension Plan that were valued using the NAV methodology were subject to redemption restrictions on their valuation date. These commingled funds are audited annually by an independent accounting firm.

In conjunction with the issuance of ASU 2015-07, Fair Value Measurements (Topic 820): Disclosures for Investment in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), QEP no longer presents its Pension Plan assets in the fair value hierarchy, in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures, as all investments are measured at NAV as a practical expedient, which are now required to be excluded from the fair value hierarchy.

The following table summarizes investments for which fair value is measured using the NAV per share practical expedient as of December 31, 2017 and 2016, respectively:

	December 31, 2017				December 31, 2016
	Total		Percentage of total		Total		Percentage of total
	(in millions, except percentages)
Cash and short-term investments	$	0.5	—	%	$	3.5	4	%
Equity securities:
Domestic	35.0		35	%	39.3		46	%
International	15.3		15	%	21.6		25	%
Fixed income	49.7		50	%	21.7		25	%
Total investments	$	100.5	100	%	$	86.1	100	%

Expected Benefit Payments

As of December 31, 2017, the following future benefit payments are expected to be paid:

	Pension Plan and SERP benefits		Medical Plan benefits
	(in millions)
2018	$	6.6	$	0.2
2019	$	8.1	$	0.2
2020	$	7.6	$	0.2
2021	$	8.3	$	0.2
2022	$	6.8	$	0.2
2023 through 2026	$	39.1	$	0.6

Employee Investment Plan

QEP employees may participate in the QEP Employee Investment Plan, a defined-contribution plan (the 401(k) Plan). The 401(k) Plan allows eligible employees to make investments, including purchasing shares of QEP common stock, through payroll deduction at the current fair market value on the transaction date. Participants receive 100% employer matching contributions on participant 401(k) plan contributions up to a percentage of qualifying earnings as described below.

	Year Ended December 31,
	2017		2016		2015
Employees not covered by the Pension Plan or SERP(1)
Maximum employer matching of qualifying earnings	8	%	8	%	8	%
Employees covered by the Pension Plan but not the SERP(1)
Maximum employer matching of qualifying earnings	8	%	8	%	6	%
Employees covered by both the Pension Plan and the SERP(1)
Maximum employer matching of qualifying earnings	6	%	6	%	6	%

_______________________

⁽¹⁾  The Pension Plan was frozen effective January 1, 2016.

The Company may contribute a discretionary portion beyond the Company's matching contribution to employees not in the Pension Plan or SERP. The Company recognizes expense equal to its yearly contributions, which amounted to $6.0 million, $5.6 million and $6.3 million during the years ended December 31, 2017, 2016 and 2015, respectively.

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Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

On December 22, 2017 the Tax Cuts and Jobs Act (H.R.1) (Tax Legislation) was signed into law, which resulted in significant changes to U.S. federal income tax law. QEP expects that these changes will positively impact QEP's future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate of 21% compared to 35%. The Tax Legislation also repeals the corporate alternative minimum tax (AMT). Several provisions of the new tax law such as limitations on the deductibility of interest expense and certain executive compensation and the inability to use Section 1031 like-kind exchanges for assets such as machinery and equipment could apply to QEP; however, we do not believe that they will materially impact QEP's financial statements. The impact of the Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made and actions the Company may take as a result of the Tax Legislation.  Additionally, guidance issued by the relevant regulatory authorities regarding the Tax Legislation may materially impact QEP's financial statements. The Company will continue to analyze the Tax Legislation to determine the full impact of the new law, on the Company's consolidated financial statements and operations.

Details of income tax provisions and deferred income taxes from continuing operations are provided in the following tables.

The components of income tax provisions and benefits were as follows:

	Year Ended December 31,
	2017			2016			2015
Federal income tax provision (benefit)	(in millions)
Current	$	2.1		$	(55.5	)	$	(112.3	)
Deferred	(339.8		)	(614.3		)	34.5
State income tax provision (benefit)
Current	0.5			(1.5		)	(6.6		)
Deferred	25.0			(36.9		)	(9.2		)
Total income tax provision (benefit)	$	(312.2	)	$	(708.2	)	$	(93.6	)

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

	Year Ended December 31,
	2017		2016		2015
Federal income taxes statutory rate	35.0	%	35.0	%	35.0	%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit(1)	(40.1	)%	2.4	%	4.2	%
Federal rate change(2)	741.3	%	—	%	—	%
State rate change	2.1	%	(1.1	)%	—	%
Penalties	(0.4	)%	—	%	(0.3	)%
Return to provision adjustment	(0.7	)%	—	%	(0.3	)%
Uncertain tax provision (federal rate change)	(7.7	)%	—	%	—	%
Other	(1.8	)%	—	%	(0.1	)%
Effective income tax rate	727.7	%	36.3	%	38.5	%

____________________________

⁽¹⁾  State income taxes changed significantly from prior years mainly due to the change in valuation allowance during the year of $36.2 million.

⁽²⁾  The new tax legislation changed the federal corporate income tax rate from 35% to 21% starting in 2018. The rate change caused the Company to revalue its deferred tax liabilities and assets as of December 31, 2017 from a 35% to 21% federal corporate income tax rate which caused the majority of the change in rate.

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

	December 31,
	2017(1)		2016
Deferred tax liabilities	(in millions)
Property, plant and equipment	$	898.7	$	1,135.0
Deferred tax assets
Net operating loss and tax credit carryforwards	$	308.8	$	161.6
Employee benefits and compensation costs	26.4		49.0
Bonus and vacation accrual	6.2		11.4
Commodity price derivatives	29.9		74.3
Other	9.4		12.8
Total deferred tax assets	380.7		309.1
Net deferred income tax liability	$	518.0	$	825.9
Balance sheet classification
Deferred income tax liability – noncurrent	518.0		825.9
Net deferred income tax liability	$	518.0	$	825.9

____________________________

⁽¹⁾  The $307.9 million decrease in net deferred income tax liability as of December 31, 2017 is primarily related to a $318.0 million decrease from the federal rate change from 35% to 21%.

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2017, are as follows:

	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2018-2037	$	95.8
State net operating loss valuation allowance		$	(56.8	)
U.S. net operating loss	2036-2037	$	250.4
U.S. alternative minimum tax credit	Indefinite	$	19.5

The valuation allowance of $56.8 million was established in 2014 and 2017 against the available state net operating loss and is related primarily to losses incurred in Oklahoma and Louisiana. Due to the 2014 property sales in the Other Southern area in which the Company sold its interests in most of its properties in Oklahoma, the Company does not forecast sufficient taxable income to utilize the net operating loss in Oklahoma. In 2017, a valuation allowance of $31.8 million was established against Louisiana's net operating loss as the Company does not forecast sufficient taxable income to utilize the entire net operating loss in Louisiana.

The Tax Legislation eliminated AMT, and allowed the ability to offset our regular tax liability or claim refunds for taxable years 2018 through 2021 for AMT credits carried forward from prior years. The Company currently anticipates it will realize approximately $19.5 million in AMT value over the next four years with approximately half of this value estimated to be realized in 2019 for taxable year 2018.

Unrecognized Tax Benefit

As of December 31, 2017 and 2016, QEP had $19.0 million and $15.6 million, respectively, of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which were recorded within "Other long-term liabilities" on the Consolidated Balance Sheets. The $15.6 million uncertain tax position the Company reported during the year ended December 31, 2016, was expensed during the year ended December 31, 2014, with an additional $3.4 million expensed during the year ended December 31, 2017 with the new Tax Legislation. The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authorities. Our policy is to recognize any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statements of Operations and to recognize any penalties related to uncertain tax positions in "General and administrative" expense on the Consolidated Statements of Operations. During the year ended December 31, 2017, the Company incurred $0.7 million of estimated interest expense related to uncertain tax positions. During the year ended December 31, 2016, the Company incurred $0.7 million of estimated interest expense and $0.6 million of estimated penalties related to uncertain tax positions.

The following is a reconciliation of our beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2017 and 2016:

	Unrecognized Tax Benefits
	2017		2016
	(in millions)
Balance as of January 1,	$	15.6	$	15.6
Federal benefit of state (change from 35% to 21%)	3.4		—
Balance as of December 31,	$	19.0	$	15.6

As of December 31, 2017 and 2016, QEP had approximately $19.0 million and $15.6 million, respectively, of unrecognized tax benefit that would impact its effective tax rate if recognized. The difference is due to the change in the Federal tax rate in 2017 from 35% to 21%, which affects the federal benefit of the state deduction to the unrecognized tax position.

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Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information [Text Block]

The following table provides a summary of unaudited quarterly financial information:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Year
2017	(in millions, except per share amounts or otherwise specified)
Revenues	$	420.1		$	383.7		$	390.1		$	429.0		$	1,622.9
Operating income (loss)	(5.2		)	(0.9		)	132.1			(24.5		)	101.5
Net income (loss)	76.9			45.4			(3.3		)	150.3			269.3
Net gain (loss) from asset sales and impairment	(0.1		)	19.8			157.1			(42.2		)	134.6
Nonrecurring items in operating income (loss)(1)	—			—			8.2			—			8.2
Per share information
Basic EPS	$	0.32		$	0.19		$	(0.01	)	$	0.62		$	1.12
Diluted EPS	0.32			0.19			(0.01		)	0.62			1.12
Production information
Total equivalent production (Mboe)	13,090.3			13,860.6			14,124.1			12,069.9			53,144.9
Total equivalent production (Bcfe)	78.6			83.2			84.7			72.1			318.6

2016
Revenues	$	261.3		$	333.7		$	382.4		$	399.7		$	1,377.1
Operating income (loss)	(1,379.0		)	(92.1		)	(93.1		)	(36.5		)	(1,600.7		)
Net income (loss)	(863.8		)	(197.0		)	(50.9		)	(133.3		)	(1,245.0		)
Net gain (loss) from asset sales and impairment	(1,181.9		)	(1.6		)	0.3			(6.1		)	(1,189.3		)
Nonrecurring items in operating income (loss)(1)	7.7			—			25.0			—			32.7
Per share information
Basic EPS	$	(4.55	)	$	(0.90	)	$	(0.21	)	$	(0.56	)	$	(5.62	)
Diluted EPS	(4.55		)	(0.90		)	(0.21		)	(0.56		)	(5.62		)
Production information
Total equivalent production (Mboe)	13,776.4			13,882.4			14,445.7			13,675.7			55,780.2
Total equivalent production (Bcfe)	82.7			83.3			86.6			82.1			334.7

____________________________

⁽¹⁾  Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017 and 2016.

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Supplemental Gas and Oil Information (Unaudited)

12 Months Ended

Dec. 31, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

The Company is making the following supplemental disclosures of oil and gas producing activities, in accordance with ASC 932, Extractive Activities – Oil and Gas, as amended by ASU 2010-03, Oil and Gas Reserve Estimation and Disclosures, and SEC Regulation S-X. The Company uses the successful efforts accounting method for its oil and gas exploration and development activities. All of QEP's properties are located in the United States.

Capitalized Costs

The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below:

	December 31,
	2017			2016
	(in millions)
Proved properties	$	12,470.9		$	14,232.5
Unproved properties, net	1,095.8			871.5
Total proved and unproved properties	13,566.7			15,104.0
Accumulated depreciation, depletion and amortization	(6,642.9		)	(8,797.7		)
Net capitalized costs	$	6,923.8		$	6,306.3

Costs Incurred

The costs incurred in oil and gas acquisition, exploration and development activities are displayed in the table below. Development costs are net of the change in accrued capital costs of $60.6 million and ARO additions and revisions of $32.0 million during the year ended December 31, 2017. The costs incurred for the development of reserves that were classified as proved undeveloped were approximately $389.3 million in 2017, $258.1 million in 2016, and $490.4 million in 2015.

	Year Ended December 31,
	2017		2016		2015
	(in millions)
Proved property acquisitions	$	269.6	$	431.6	$	49.6
Unproved property acquisitions	532.4		208.7		39.8
Other acquisitions	13.2		—		—
Exploration costs (capitalized and expensed)	32.7		13.4		8.7
Development costs	1,189.3		509.2		1,010.3
Total costs incurred	$	2,037.2	$	1,162.9	$	1,108.4

Results of Operations

Following are the results of operations of QEP's oil and gas producing activities, before allocated corporate overhead and interest expenses.

	Year Ended December 31,
	2017			2016			2015
	(in millions)
Revenues	$	1,548.1		$	1,271.0		$	1,390.4
Production costs	675.4			616.7			654.1
Exploration expenses	22.0			1.7			2.7
Depreciation, depletion and amortization	735.1			852.3			870.8
Impairment	72.3			1,194.3			55.6
Total expenses	1,504.8			2,665.0			1,583.2
Income (loss) before income taxes	43.3			(1,394.0		)	(192.8		)
Income tax benefit (expense)	(16.0		)	517.2			70.6
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	27.3		$	(876.8	)	$	(122.2	)

Estimated Quantities of Proved Oil and Gas Reserves

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 oversight of a multi-functional Reserves Review Committee reporting to the Company's Audit Committee of the Board of Directors. The Company retained Ryder Scott Company, L.P. (RSC), independent oil and gas reserve evaluation engineering consultants, to prepare the estimates of all of its proved reserves as of December 31, 2017 and 2016, and retained RSC and DeGolyer and MacNaughton to prepare the estimates of all of its proved reserves as of December 31, 2015. The estimated proved reserves have been prepared in accordance with the SEC's Regulation S-X and ASC 932 as amended. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

All of QEP's proved undeveloped reserves at December 31, 2017, are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves. The Company plans to continue development of its leaseholds and anticipates that it will have the financial capability to continue development in the manner estimated. While the majority of QEP's PUD reserves are located on leaseholds that are held by production, any PUD locations on expiring leaseholds are scheduled for development during the primary term of the lease.

As of December 31, 2017, all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's change in quantities of proved oil, gas and NGL reserves for the years ended December 31, 2015, 2016 and 2017 are as follows:

	Oil		Gas		NGL		Total(13)
	(MMbbl)		(Bcf)		(MMbbl)		(MMboe)
Balance at December 31, 2014	172.5		2,317.2		96.6		655.3
Revisions of previous estimates(1)	(47.0	)	(463.8	)	(55.3	)	(179.6	)
Extensions and discoveries(2)	85.6		467.7		21.8		185.4
Purchase of reserves in place(3)	2.0		3.2		0.6		3.1
Sale of reserves in place(4)	(0.4	)	(34.3	)	(0.2	)	(6.3	)
Production	(19.6	)	(181.1	)	(4.7	)	(54.5	)
Balance at December 31, 2015	193.1		2,108.9		58.8		603.4
Revisions of previous estimates(5)	(9.7	)	412.8		(0.3	)	58.8
Extensions and discoveries(6)	13.0		158.1		3.3		42.6
Purchase of reserves in place(7)	62.7		54.6		11.5		83.3
Sale of reserves in place(8)	(0.2	)	(3.6	)	(0.1	)	(0.9	)
Production	(20.3	)	(177.0	)	(6.0	)	(55.8	)
Balance at December 31, 2016	238.6		2,553.8		67.2		731.4
Revisions of previous estimates(9)	3.7		12.5		(3.1	)	2.7
Extensions and discoveries(10)	59.1		101.9		10.4		86.4
Purchase of reserves in place(11)	46.6		125.5		8.7		76.3
Sale of reserves in place(12)	(7.9	)	(831.2	)	(12.6	)	(159.0	)
Production	(19.6	)	(168.9	)	(5.4	)	(53.1	)
Balance at December 31, 2017	320.5		1,793.6		65.2		684.7
Proved developed reserves
Balance at December 31, 2014	99.3		1,288.4		52.2		366.2
Balance at December 31, 2015	109.7		1,245.3		34.4		351.6
Balance at December 31, 2016	103.2		1,309.8		35.7		357.2
Balance at December 31, 2017	116.0		655.5		27.9		253.1
Proved undeveloped reserves
Balance at December 31, 2014	73.2		1,028.8		44.4		289.1
Balance at December 31, 2015	83.4		863.6		24.4		251.8
Balance at December 31, 2016	135.4		1,244.0		31.5		374.2
Balance at December 31, 2017	204.5		1,138.1		37.3		431.6

___________________________

⁽¹⁾  Revisions of previous estimates in 2015 include: 126.2 MMboe of negative revisions due to lower pricing and 67.2 MMboe of negative revisions unrelated to pricing, partially offset by 13.7 MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and the Uinta Basin.

⁽²⁾  Extensions and discoveries in 2015 increased proved reserves by 185.4 MMboe, primarily related to extensions and discoveries in the Williston Basin of 68.2 MMboe, the Uinta Basin of 53.2 MMboe, and the Permian Basin of 49.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations.

⁽³⁾  Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP operated wells in the Williston and Permian basins as discussed in Note 2 – Acquisitions and Divestitures.

⁽⁴⁾  Sale of reserves in place in 2015 relate to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures.

⁽⁵⁾  Revisions of previous estimates in 2016 include 77.3 MMboe of positive revisions, primarily related to successful workovers in Haynesville/Cotton Valley; reserves associated with increased density wells in areas that have been previously developed on lower density spacing; and 5.5 MMboe of positive performance revisions. These positive revisions were partially offset by 18.5 MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices.

⁽⁶⁾  Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations.

⁽⁷⁾  Purchase of reserves in place in 2016 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.

⁽⁸⁾  Sale of reserves in place in 2016 relates to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures.

⁽⁹⁾  Revisions of previous estimates in 2017 include 2.7 MMboe of positive revisions, primarily related to 32.0 MMboe of positive revisions related to pricing, driven by higher oil, gas and NGL prices and 2.2 MMboe of positive performance revisions. These positive revisions were partially offset by 11.0 MMboe of negative revisions related to higher operating costs and 20.5 MMboe of other revisions primarily from changing to a horizontal development plan from a vertical well development plan in the Uinta Basin and increased longer laterals in Haynesville/Cotton Valley. These negative other revisions are partially offset by positive other revisions from successful infill drilling in Haynesville/Cotton Valley and the Williston Basin.

⁽¹⁰⁾  Extensions and discoveries in 2017 primarily related to new well completions and associated new PUD locations in the Permian Basin.

⁽¹¹⁾  Purchase of reserves in place in 2017 was primarily related to QEP's 2017 Permian Basin Acquisition and various other acquired oil and gas properties as discussed in Note 2 – Acquisitions and Divestitures.

⁽¹²⁾  Sale of reserves in place in 2017 was primarily related to QEP's Pinedale Divestiture as discussed in Note 2 – Acquisitions and Divestitures.

⁽¹³⁾  Generally, gas consumed in operations was excluded from reserves, however, in some cases, produced gas consumed in operations was included in reserves when the volumes replaced fuel purchases.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

Future net cash flows were calculated at December 31, 2017, 2016 and 2015, by applying prices, which were the simple average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for each of the 12 months during 2017, 2016 and 2015, with consideration of known contractual price changes. The prices used do not include any impact of QEP's commodity derivatives portfolio. The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:

	For the year ended December 31,
	2017		2016		2015
Average benchmark price per unit:
Oil price (per bbl)	$	51.34	$	42.75	$	50.28
Gas price (per MMBtu)	$	2.98	$	2.48	$	2.59

Year ended operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop proved undeveloped reserves are approximately $486.5 million in 2018, $710.0 million in 2019 and $1,006.2 million in 2020. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. QEP believes cash flow from its operating activities, cash on hand and borrowings under its revolving credit facility will be sufficient to cover these estimated future development costs. In addition, QEP estimates that its future development costs relating to wells waiting on completion and its refracturing program, which are not classified as PUD, are approximately $132.6 million in 2018.

The assumptions used to derive the standardized measure of discounted future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes but should not be solely relied upon in evaluating QEP or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below:     

• Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations.

• Future operating and capital costs will likely differ from those required to be used in these calculations.

• Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and gas may cause production rates in future years to vary significantly from those rates used in the calculations.

• Future revenues may be subject to different production, severance and property taxation rates.

• The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.

The standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below:

	Year Ended December 31,
	2017			2016			2015
	(in millions)
Future cash inflows	$	22,028.9		$	16,239.8		$	15,325.3
Future production costs	(9,074.2		)	(7,789.0		)	(7,389.9		)
Future development costs(1)	(4,726.0		)	(3,432.9		)	(2,202.5		)
Future income tax expenses(2)	(1,439.1		)	(913.4		)	(1,169.3		)
Future net cash flows	6,789.6			4,104.5			4,563.6
10% annual discount for estimated timing of net cash flows	(3,692.3		)	(2,176.5		)	(2,087.3		)
Standardized measure of discounted future net cash flows	$	3,097.3		$	1,928.0		$	2,476.3

___________________________

⁽¹⁾  Future development costs include future abandonment and salvage costs.

⁽²⁾  The standardized measure of discounted future net cash flows for the year ended December 31, 2017, assumes the new 21% federal tax rate from the Tax Legislation enacted in December 2017.

The principal sources of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below:

	Year Ended December 31,
	2017			2016			2015
	(in millions)
Balance at January 1,	$	1,928.0		$	2,476.3		$	5,340.0
Sales of oil, gas and NGL produced, net of production costs	(872.7		)	(654.3		)	(736.3		)
Net change in sales prices and in production (lifting) costs related to future production	1,457.2			(739.4		)	(6,307.8		)
Net change due to extensions and discoveries	556.8			81.8			1,765.7
Net change due to revisions of quantity estimates	9.9			122.7			(1,350.2		)
Net change due to purchases of reserves in place	342.7			256.5			29.7
Net change due to sales of reserves in place	(504.7		)	(4.3		)	(48.8		)
Previously estimated development costs incurred during the period	475.4			374.6			865.0
Changes in estimated future development costs	(283.4		)	(476.5		)	560.7
Accretion of discount	235.7			311.1			752.9
Net change in income taxes	(227.4		)	205.4			1,554.4
Other	(20.2		)	(25.9		)	51.0
Net change	1,169.3			(548.3		)	(2,863.7		)
Balance at December 31,	$	3,097.3		$	1,928.0		$	2,476.3

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Subsequent Event (Notes)

12 Months Ended

Dec. 31, 2017

Subsequent Event [Abstract]

Subsequent Events [Text Block]

Note 15 – Subsequent Event

In February 2018, in conjunction with the 2017 Permian Basin Acquisition, QEP entered into agreements to acquire oil and gas properties in the Permian Basin for an aggregate purchase price of $36.1 million, subject to customary purchase price adjustments. The transactions are expected to be funded with borrowings under the credit facility and are expected to close in the first half of 2018.

In February 2018, the Board of Directors approved a retention and severance program in conjunction with the announcement of several strategic initiatives, which include selling assets and focusing the Company's activities on its Permian Basin operations. The estimated amount of general and administrative expenses to be incurred related to this program in 2018 is approximately $20.0 million.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Summary of Significant Accounting Policies [Abstract]

Nature of Business [Text Block]

Nature of Business

QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Northern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP".

Principles of Consolidation [Policy Text Block]

Principles of Consolidation

The Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Consolidated Financial Statements were prepared in accordance with GAAP and with the instructions for annual reports on Form 10-K and Regulations S-X. All significant intercompany accounts and transactions have been eliminated in consolidation.

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

Termination of Marketing Agreements [Policy Text Block]

Termination of Marketing Agreements

Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and Haynesville Gathering. As a result, QEP Energy directly markets its own oil, gas and NGL production. While QEP continues to act as an agent for the sale of oil, gas and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had prior to 2016.

In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP had one reportable segment effective January 1, 2016. The Company has recast its financial statements for historical periods to reflect the impact of the termination of marketing agreements to show its financial results without segments.

Reclassifications [Policy Text Block]

Reclassifications

Certain prior period amounts on the Consolidated Statements of Operations, Consolidated Balance Sheets and Consolidated Statements of Cash Flows have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's net income (loss), earnings (loss) per share, cash flows, current assets or retained earnings previously reported.

Use of Estimates [Policy Text Block]

Use of Estimates

The preparation of the Consolidated Financial Statements and Notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management's estimates and assumptions is the estimate of proved oil, gas and NGL reserves, which are used in the calculation of depreciation, depletion and amortization rates of its oil and gas properties, impairment of proved properties and asset retirement obligations. Changes in estimated quantities of its reserves could impact the Company's reported financial results as well as disclosures regarding the quantities and value of proved oil and gas reserves. Other items subject to estimates and assumptions include the carrying amount of property, plant and equipment, assigning fair value and allocating purchase price in connection with business combinations, valuation allowances for receivables, income taxes, valuation of derivatives instruments, accrued liabilities, accrued revenue and related receivables and obligations related to employee benefits, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Risks And Uncertainties [Policy Text Block]

Risks and Uncertainties

The Company's revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil, gas and NGL, which are affected by many factors outside of QEP's control, including changes in market supply and demand. Changes in market supply and demand are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. Field-level prices received for QEP's oil and gas production have historically been volatile and may be subject to significant fluctuations in the future. The Company's derivative contracts serve to mitigate in part the effect of this price volatility on the Company's cash flows, and the Company has derivative contracts in place for a portion of its expected future oil and gas production. Refer to Note 6 – Derivative Contracts for the Company's open oil and gas commodity derivative contracts.

Revenue Recognition [Policy Text Block]

Revenue Recognition

QEP recognizes revenue from oil and gas producing activities in the period that services are provided or products are delivered. Revenues associated with the sale of oil, gas and NGL are accounted for using the sales method, whereby revenue is recognized when these commodities are sold to purchasers. Revenues include estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators. An imbalance liability is recorded to the extent that QEP has sold volumes in excess of its share of remaining reserves in an underlying property.

QEP also purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. QEP recognizes revenue from these resale activities when title transfers to the customer.

Cash and Cash Equivalents and Restricted Cash [Policy Text Block]

Cash and Cash Equivalents and Restricted Cash

Cash equivalents consist principally of highly liquid investments in securities with original maturities of three months or less made through commercial bank accounts that result in available funds the next business day.

As of December 31, 2017, QEP had no unrestricted cash and restricted cash of $23.4 million. As of December 31, 2016, QEP had unrestricted cash of $443.8 million and restricted cash of $21.6 million. QEP's restricted cash is primarily cash deposited into an escrow account related to a title dispute between third parties in the Williston Basin and is included in "Other noncurrent assets" on the Consolidated Balance Sheets.

Supplemental cash flow information is shown in the table below:

	Year Ended December 31,
	2017			2016			2015
Supplemental Disclosures	(in millions)
Cash paid for interest, net of capitalized interest	$	134.9		$	139.1		$	139.4
Cash paid (refund received) for income taxes, net	$	(0.3	)	$	(123.5	)	$	487.8
Non-cash investing activities
Change in capital expenditure accrual balance	$	60.2		$	(32.8	)	$	(129.2	)

Accounts Receivable [Policy Text Block]

Accounts Receivable

Accounts receivable consists mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company's oil and gas receivables are collected and bad debts are minimal. However, if commodity prices remain low for an extended period of time, the Company could incur increased levels of bad debt expense. Recovery of bad debt associated with accounts receivable for the year ended December 31, 2017 was $1.0 million. Bad debt expense associated with accounts receivable for the years ended December 31, 2016 and 2015, was $1.8 million, and $0.5 million, respectively. Bad debt recovery or expense is included in "General and administrative" expense on the Consolidated Statements of Operations. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. The allowance for bad debt expenses was $1.6 million at December 31, 2017, and $4.8 million at December 31, 2016.

Property, Plant and Equipment [Policy Text Block]

Property, Plant and Equipment

Property, plant and equipment balances are stated at historical cost. Material and supplies inventories are valued at the lower of cost or net realizable value. Maintenance and repair costs are expensed as incurred. Significant accounting policies for our property, plant and equipment are as follows:

Successful Efforts Accounting for Oil and Gas Operations

The Company follows the successful efforts method of accounting for oil and gas property acquisitions, exploration, development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected. Capitalized costs of unproved properties are reclassified to proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.

Capitalized Exploratory Well Costs

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

Depreciation, Depletion and Amortization (DD&A)

Capitalized proved leasehold costs are depleted on a field-by-field basis using the unit-of-production method and the estimated proved oil and gas reserves. Capitalized costs of exploratory wells that have found proved oil and gas reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves for a successful effort field. The Company capitalizes an estimate of the fair value of future abandonment costs.

DD&A for the Company's remaining properties is generally based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets using the straight-line method. The estimated useful lives of those assets depreciated under the straight-line basis generally range as follows:

Buildings	10 to 30 years
Leasehold improvements	3 to 10 years
Service, transportation and field service equipment	3 to 7 years
Furniture and office equipment	3 to 7 years

Impairment of Long-Lived Assets

Proved oil and gas properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value. Triggering events could include, but are not limited to, a reduction of oil, gas and NGL reserves caused by mechanical problems, faster-than-expected decline of production, lease ownership issues, and declines in oil, gas and NGL prices. If impairment is indicated, fair value is estimated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices, operating costs and estimates of proved, probable and possible reserves. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors.

Unproved properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.

During the year ended December 31, 2017, QEP recorded impairment charges of $78.9 million, of which $38.1 million was related to proved properties due to lower future gas prices, $29.0 million was primarily related to unproved leasehold acreage in the Central Basin Platform (Refer to Note 3 – Capitalized Exploratory Well Costs for additional information), $6.5 million was related to impairment of an underground gas storage facility and $5.3 million was related to the impairment of goodwill. Of the $38.1 million impairment of proved properties, $37.1 million related to the Other Northern area and $1.0 million related to Louisiana properties.

During the year ended December 31, 2016, QEP recorded impairment charges of $1,194.3 million, of which $1,172.7 million was related to proved properties due to lower future oil and gas prices, $17.9 million was related to expiring leaseholds on unproved properties and $3.7 million was related to the impairment of goodwill. Of the $1,172.7 million impairment of proved properties, $1,164.0 million related to Pinedale properties, $4.7 million related to Uinta Basin properties, $3.4 million related to the Other Northern area and $0.6 million related to QEP's remaining Other Southern properties.

During the year ended December 31, 2015, QEP recorded impairment charges of $55.6 million, of which $39.3 million was related to proved properties due to lower future oil and gas prices, $2.0 million was related to expiring leaseholds on unproved properties and $14.3 million was related to the impairment of goodwill. Of the $39.3 million impairment on proved properties, $20.2 million related to QEP's remaining Other Southern properties, $18.4 million related Other Northern properties, and $0.7 million related to Permian Basin properties.

Asset Retirement Obligations

QEP is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. ARO associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement costs, is depreciated over the useful life of the asset. ARO are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded to both the ARO liability and the long-lived asset. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. Refer to Note 4 – Asset Retirement Obligations for additional information.

Goodwill [Policy Text Block]

Goodwill

Goodwill represents the excess of the amount paid over the fair value of assets acquired in a business combination and is not subject to amortization. During the year ended December 31, 2017, QEP early adopted ASU 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment. Under the new guidance QEP performs an annual goodwill impairment test by comparing the fair value of a reporting unit with its carry amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. QEP determines the fair value of its reporting units in which goodwill is allocated using the income approach in which the fair value is estimated based on the value of expected future cash flows. Key assumptions used in the cash flow model include estimated quantities of oil, gas and NGL reserves, including both proved reserves and risk-adjusted unproved reserves, and including probable and possible reserves; estimates of market prices considering forward commodity price curves as of the measurement date; estimates of revenue and operating costs over a multi-year period; and estimates of capital costs.

During the year ended December 31, 2017, QEP recorded $5.3 million of goodwill, which related to an acquisition in the first quarter of 2017. During the fourth quarter of 2017, QEP performed an annual impairment test over goodwill as described above, which resulted in a full write down of goodwill of $5.3 million.

During the years ended December 31, 2016 and 2015, QEP recorded $3.7 million and $14.3 million, respectively, of goodwill. Annual impairment tests over goodwill at year end December 31, 2016 and 2015 resulted in a full write down of $3.7 million and $14.3 million, respectively.

Litigation and Other Contingencies [Policy Text Block]

Litigation and Other Contingencies

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Consolidated Financial Statements. The amount of ultimate loss may differ from these estimates. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Refer to Note 9 – Commitments and Contingencies for additional information.

QEP accrues material losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.

Derivative Contracts [Policy Text Block]

Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. QEP uses commodity derivative instruments, typically fixed-price swaps and costless collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. QEP does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. Additionally, QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates.

These derivative contracts are recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Consolidated Statements of Operations in the month of settlement and are also marked-to-market monthly. Refer to Note 6 – Derivative Contracts for additional information.

Credit Risk [Policy Text Block]

Credit Risk

Management believes that its credit review procedures, loss reserves, cash deposits and investments, and collection procedures have adequately provided for usual and customary credit-related losses. Exposure to credit risk may be affected by extended periods of low commodity prices, as well as the concentration of customers in certain regions due to changes in economic or other conditions. Customers include commercial and industrial enterprises and financial institutions that may react differently to changing conditions.

The Company utilizes various processes to monitor and evaluate its credit risk exposure, which include closely monitoring current market conditions and counterparty credit fundamentals, including public credit ratings, where available. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals, and is aggregated across all lines of business, including derivatives, physical exposure and short-term cash investments. To further manage the level of credit risk, the Company requests credit support and, in some cases, requests parental guarantees, letters of credit or prepayment from companies with perceived higher credit risk. Loss reserves are periodically reviewed for adequacy and may be established on a specific case basis. The Company also has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation.

The Company enters into International Swap Dealers Association Master Agreements (ISDA Agreements) with each of its derivative counterparties prior to executing derivative contracts. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or counterparty to a derivative contract. The Company routinely monitors and manages its exposure to counterparty risk related to derivative contracts by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties public credit ratings, and avoiding concentration of credit exposure by transacting with multiple counterparties. The Company's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings.

The Company's five largest customers accounted for 59%, 48%, and 30% of QEP's revenues for the years ended December 31, 2017, 2016 and 2015, respectively. During the year ended December 31, 2017, Shell Trading Company, Occidental Energy Marketing, Andeavor Logistics LP, BP Energy Company and Plains Marketing LP accounted for 14%, 13%, 13%, 10% and 10%, respectively, of QEP's total revenues. During the year ended December 31, 2016, Shell Trading Company, BP Energy Company and Valero Marketing & Supply Company accounted for 14%, 10% and 10%, respectively, of QEP's total revenues. During the year ended December 31, 2015, no customer accounted for 10% or more of QEP's total revenues. 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.

Income Taxes [Policy Text Block]

Income Taxes

The amount of income taxes recorded by QEP requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. QEP has recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. Deferred income taxes are provided for the temporary differences arising between the book and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods.

ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company's recorded income tax benefits will be fully realized, except as noted below. As of December 31, 2017, the Company had a valuation allowance of $56.8 million against the state net operating loss deferred tax asset because management does not forecast future income in Oklahoma and Louisiana to offset net operating losses before they expire. All federal income tax returns prior to 2017 have been examined by the Internal Revenue Service and are closed. Income tax returns for 2017 have not yet been filed. Most state tax returns for 2014 and subsequent years remain subject to examination.

The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more-likely-than-not to be sustained upon examination by the relevant taxing authorities. Our policy is to recognize any interest earned on income tax refunds in "Interest and other income (expense)" on the Consolidated Statements of Operations, any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statements of Operations and to recognize any penalties related to uncertain tax positions in "General and administrative" expense on the Consolidated Statements of Operations. As of December 31, 2017 and 2016, QEP had $19.0 million and $15.6 million of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which was included within "Other long-term liabilities" on the Consolidated Balance Sheets. During the year ended December 31, 2017, the Company incurred $0.7 million of estimated interest expense related to uncertain tax positions. During the year ended December 31, 2016, the Company incurred $0.7 million of estimated interest expense and $0.6 million of estimated penalties related to uncertain tax positions. During the year ended December 31, 2015, the Company incurred $0.5 million of estimated interest expense and $2.2 million of estimated penalties related to uncertain tax positions.

Treasury Stock [Policy Text Block]

Treasury Stock

We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders' equity in the Consolidated Balance Sheets. QEP acquires treasury stock from stock forfeitures and withholdings and uses the acquired treasury stock for stock option exercises and certain stock grants to employees; refer to Note 10 – Share-Based Compensation for additional information.

Earnings Per Share [Policy Text Block]

Earnings (Loss) Per Share

Basic earnings (loss) per share (EPS) are computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP's unvested restricted share awards are included in weighted-average basic common shares outstanding because, once the shares are granted, the restricted share awards are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted share awards are eligible to receive dividends.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings (loss) per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) per common share. For the years ended December 31, 2017 and 2015, there were no anti-dilutive shares. For the year ended December 31, 2016, there were 0.1 million shares not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss from continuing operations.

The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation:

	December 31,
	2017	2016	2015
	(in millions)
Weighted-average basic common shares outstanding	240.6	221.7	176.6
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—
Average diluted common shares outstanding	240.6	221.7	176.6

Share-based Compensation [Policy Text Block]

Share-Based Compensation

QEP issues stock options, restricted share awards and restricted share units to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. The grant date fair value for restricted share awards is determined based on the closing bid price of the Company's common stock on the grant date. Share-based compensation cost for restricted share units is equal to its fair value as of the end of the period and is classified as a liability. QEP uses an accelerated method in recognizing share-based compensation costs for stock options and restricted share awards with graded-vesting periods. Stock options held by employees generally vest in three equal, annual installments and primarily have a term of seven years. Restricted share awards and restricted share units vest in equal installments over a specified number of years after the grant date with the majority vesting in three years. Non-vested restricted share awards have voting and dividend rights; however, sale or transfer is restricted. Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified unfunded deferred compensation plan at the time of vesting. The Company also awards performance share units under its CIP that are generally paid out in cash depending upon the Company's total shareholder return compared to a group of its peers over a three-year period. Share-based compensation cost for the performance share units is equal to its fair value as of the end of the period and is classified as a liability. For additional information, refer to Note 10 – Share-Based Compensation for additional information.

Pension and Other Postretirement Benefits [Policy Text Block]

Pension and Other Postretirement Benefits

QEP maintains closed, defined-benefit pension and other postretirement benefit plans, including both a qualified and a supplemental plan. QEP also provides certain health care and life insurance benefits for certain retired QEP employees. Determination of the benefit obligations for QEP's defined-benefit pension and other postretirement benefit plans impacts the recorded amounts for such obligations on the Consolidated Balance Sheets and the amount of benefit expense recorded to the Consolidated Statements of Operations.

QEP measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement benefit plans include the discount rate, the expected rate of return on plan assets (for funded pension plans) and the rate of future compensation increases. Other assumptions involve demographic factors such as retirement, mortality and turnover. QEP evaluates and updates its actuarial assumptions at least annually. QEP recognizes a pension curtailment immediately when there is a significant reduction in, or an elimination of, defined-benefit accruals for present employees' future services. Refer to Note 11 – Employee Benefits for additional information.

Comprehensive Income [Policy Text Block]

Comprehensive Income (Loss)

Comprehensive income (loss) is the sum of net income (loss) as reported in the Consolidated Statements of Operations and changes in the components of other comprehensive income. Other comprehensive income (loss) includes certain items that are recorded directly to equity and classified as accumulated other comprehensive income (AOCI), which includes changes in the underfunded portion of the Company's defined-benefit pension and other postretirement benefits plans and changes in deferred income taxes on such amounts. These transactions do not represent the culmination of the earnings process but result from periodically adjusting historical balances to fair value.

Recent Accounting Developments [Policy Text Block]

Recent Accounting Developments

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In addition, new and enhanced disclosures will be required. The amendment is effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 15, 2016. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The Company does not expect net income (loss) or cash flows to be materially impacted by the new standard; however, the Company expects that a portion of its transportation and processing costs will be netted within revenue under the new standard. In addition, the Company will have expanded disclosure requirements, as a result of the adoption of the ASU. The Company has selected the modified retrospective method and will adopt this guidance on the effective date of January 1, 2018.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-06, Derivatives and hedging (Topic 815): Contingent put and call options in debt instruments, which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The amendment was effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption was permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment was effective prospectively for reporting periods beginning after December 15, 2016, and early adoption was permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of certain cash receipts and cash payments , which intends to reduce the diversity in practice in how certain transactions are classified in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the fourth quarter of 2017 and the adoption of this standard did not have a material impact on the Company's Consolidated Financial Statements.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the definition of a business, which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of businesses. The amendment will be effective prospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the fourth quarter of 2017 and the adoption of this standard did not have a material impact on the Company's Consolidated Financial Statements; however, this standard may impact the determination of whether future acquisitions are accounted for as a business combination or an asset acquisition.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment, which eliminates the requirement to calculate implied fair value of goodwill to measure the goodwill impairment charge. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements.

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, which changes how employers of a defined benefit plan present net periodic benefit cost in the statements of operations. The amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and recast the years ended December 31, 2016 and 2015. The adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements. Refer to Note 11 – Employee Benefits for additional information regarding the Company's pension and other postretirement plans.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Summary of Significant Accounting Policies [Abstract]

Supplemental Cash Flow Information [Table Text Block]

Supplemental cash flow information is shown in the table below:

	Year Ended December 31,
	2017			2016			2015
Supplemental Disclosures	(in millions)
Cash paid for interest, net of capitalized interest	$	134.9		$	139.1		$	139.4
Cash paid (refund received) for income taxes, net	$	(0.3	)	$	(123.5	)	$	487.8
Non-cash investing activities
Change in capital expenditure accrual balance	$	60.2		$	(32.8	)	$	(129.2	)

Property, Plant and Equipment [Table Text Block]

Buildings	10 to 30 years
Leasehold improvements	3 to 10 years
Service, transportation and field service equipment	3 to 7 years
Furniture and office equipment	3 to 7 years

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation:

	December 31,
	2017	2016	2015
	(in millions)
Weighted-average basic common shares outstanding	240.6	221.7	176.6
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—
Average diluted common shares outstanding	240.6	221.7	176.6

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Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Schedule of Purchase Price Allocation [Table Text Block]

Consideration:
Total consideration	$	591.0
Amounts recognized for fair value of assets acquired and liabilities assumed:
Proved properties	$	406.2
Unproved properties	214.2
Asset retirement obligations	(11.6		)
Bargain purchase gain	(17.8		)
Total fair value	$	591.0

Business Acquisition, Pro Forma Information [Table Text Block]

	Year ended December 31,
	2016
	Actual			Pro forma
	(in millions, except per share amounts)
Revenues	$	1,377.1		$	1,392.5
Net income (loss)	$	(1,245.0	)	$	(1,246.8	)
Earnings (loss) per common share
Basic	$	(5.62	)	$	(5.62	)
Diluted	$	(5.62	)	$	(5.62	)

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Capitalized Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2017

Capitalized Exploratory Well Costs [Abstract]

Capitalized Exploratory Well Costs, Roll Forward [Table Text Block]

	Capitalized Exploratory Well Costs
	2017			2016			2015
	(in millions)
Balance at January 1,	$	14.2		$	2.6		$	12.6
Additions to capitalized exploratory well costs	10.7			11.7			6.0
Reclassifications to proved properties	(3.6		)	—			(16.0		)
Capitalized exploratory well costs charged to expense	(21.3		)	(0.1		)	—
Balance at December 31,	$	—		$	14.2		$	2.6

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The following is a reconciliation of the changes in the Company's ARO for the periods specified below:

	Asset Retirement Obligations
	2017			2016
	(in millions)
ARO liability at January 1,	$	231.6		$	206.8
Accretion	7.7			8.9
Additions(1)	23.5			17.0
Revisions	8.5			6.5
Liabilities related to assets sold(2)	(34.9		)	—
Liabilities settled	(22.3		)	(7.6		)
ARO liability at December 31,	$	214.1		$	231.6

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair value and related carrying amount of certain financial instruments

The fair value of financial assets and liabilities at December 31, 2017 and 2016, is shown in the table below:

	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
	December 31, 2017
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	20.6	$	—	$	(17.2	)	$	3.4
Fair value of derivative contracts – long-term	—		2.3		—		(2.2		)	0.1
Total financial assets	$	—	$	22.9	$	—	$	(19.4	)	$	3.5
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	120.8	$	—	$	(17.2	)	$	103.6
Fair value of derivative contracts – long-term	—		34.0		—		(2.2		)	31.8
Total financial liabilities	$	—	$	154.8	$	—	$	(19.4	)	$	135.4
	December 31, 2016
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	—	$	—	$	—		$	—
Fair value of derivative contracts – long-term	—		—		—		—			—
Total financial assets	$	—	$	—	$	—	$	—		$	—
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	169.8	$	—	$	—		$	169.8
Fair value of derivative contracts – long-term	—		32.0		—		—			32.0
Total financial liabilities	$	—	$	201.8	$	—	$	—		$	201.8

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K:

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	December 31, 2017				December 31, 2016
Financial Assets	(in millions)
Cash and cash equivalents	$	—	$	—	$	443.8	$	443.8
Financial Liabilities
Checks outstanding in excess of cash balances	$	44.0	$	44.0	$	12.3	$	12.3
Long-term debt	$	2,160.8	$	2,256.2	$	2,020.9	$	2,104.3

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Derivative Contracts (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Volumes and Average Prices

Derivative Contracts – Production

The following table presents QEP's volumes and average prices for its commodity derivative swap contracts as of December 31, 2017:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2018	NYMEX WTI	16.8	$	52.48
2019	NYMEX WTI	8.0	$	51.78
Gas sales		(MMBtu)	($/MMBtu)
2018 (Full Year)	NYMEX HH	109.5	$	2.99
2018 (July through December)	NYMEX HH	1.8	$	3.01
2019	NYMEX HH	36.5	$	2.88

QEP uses oil and gas basis swaps, combined with NYMEX WTI and NYMEX HH fixed price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table presents details of QEP's oil and gas basis swaps as of December 31, 2017:

Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2018 (Full Year)	NYMEX WTI	Argus WTI Midland	7.3	$	(1.06	)
2018 (July through December)	NYMEX WTI	Argus WTI Midland	0.9	$	(0.71	)
2019	NYMEX WTI	Argus WTI Midland	4.0	$	(0.80	)
Gas sales			(MMBtu)	($/MMBtu)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)

Derivative Contracts – Gas Storage

QEP enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage. The following table presents QEP's volumes and average prices for its gas storage commodity derivative swap contracts as of December 31, 2017:

Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2018	SWAP	IFNPCR	0.6	$	3.06

Fair values of Derivatives by Balance Sheet Location

		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
		December 31,
	Balance Sheet line item	2017		2016		2017		2016
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	20.6	$	—	$	120.8	$	169.8
Long-term:
Commodity	Fair value of derivative contracts	2.3		—		34.0		32.0
Total derivative instruments		$	22.9	$	—	$	154.8	$	201.8

Effects of Derivative Transactions

Derivative contracts not designated as cash flow hedges	Year Ended December 31,
	2017			2016			2015
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	6.8		$	86.3		$	353.7
Gas derivative contracts	(22.3		)	44.8			103.4
Gas Storage
Gas derivative contracts	—			2.9			3.8
Realized gains (losses) on commodity derivative contracts	(15.5		)	134.0			460.9
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(66.2		)	(217.2		)	(244.9		)
Gas derivative contracts	133.6			(145.4		)	62.0
Gas Storage
Gas derivative contracts	2.5			(4.4		)	(0.8		)
Unrealized gains (losses) on commodity derivative contracts	69.9			(367.0		)	(183.7		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts	$	54.4		$	(233.0	)	$	277.2
Derivatives associated with the Pinedale Divestiture(1)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	(1.3	)	$	—		$	—
Gas derivative contracts	(23.5		)	—			—
NGL derivative contracts	(5.1		)	—			—
Unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture	$	(29.9	)	$	—		$	—
Total realized and unrealized gains (losses) on commodity derivative contracts	$	24.5		$	(233.0	)	$	277.2

_______________________

⁽¹⁾  The unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 2 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations.

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Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Debt Outstanding

	December 31,
	2017			2016
	(in millions)
Revolving Credit Facility due 2022	$	89.0		$	—
6.80% Senior Notes due 2018(1)	—			134.0
6.80% Senior Notes due 2020(1)	51.7			136.0
6.875% Senior Notes due 2021(1)	397.6			625.0
5.375% Senior Notes due 2022	500.0			500.0
5.25% Senior Notes due 2023	650.0			650.0
5.625% Senior Notes due 2026(1)	500.0			—
Less: unamortized discount and unamortized debt issuance costs	(27.5		)	(24.1		)
Total long-term debt outstanding	$	2,160.8		$	2,020.9

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]

Annual payments and the corresponding years for gathering, processing, transportation, storage, drilling, and fractionation contracts are as follows (in millions):

Year	Amount
2018	$	95.6
2019	$	68.4
2020	$	54.9
2021	$	29.9
2022	$	28.3
After 2022	$	122.5

Operating Leases of Lessee Disclosure [Table Text Block]

Minimum future payments under the terms of long-term operating leases for the Company's primary office locations are as follows (in millions):

Year	Amount
2018	$	7.0
2019	$	7.2
2020	$	7.4
2021	$	7.4
2022	$	7.2
After 2022	$	4.8

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Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2017

Share-based Compensation [Abstract]

Share-based Compensation Expense [Table Text Block]

	Year Ended December 31,
	2017			2016		2015
	(in millions)
Stock options	$	2.3		$	2.3	$	2.9
Restricted share awards	24.6			23.7		25.6
Performance share units	(4.5		)	9.4		6.2
Restricted share units	—			0.2		—
Total share-based compensation expense	$	22.4		$	35.6	$	34.7

Schedule of calculated fair value of options granted and major assumptions used [Table Text Block]

The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:

	Stock Option Assumptions
	Year Ended December 31,
	2017			2016			2015
Weighted-average grant date fair value of awards granted during the period	$	6.44		$	3.77		$	6.82
Risk-free interest rate range	1.66% - 1.81%			0.99% - 1.15%			1.38% - 1.38%
Weighted-average risk-free interest rate	1.8		%	1.2		%	1.4		%
Expected price volatility range	43.82% - 46.70%			43.42% - 43.66%			36.8% - 36.8%
Weighted-average expected price volatility	43.9		%	43.4		%	36.8		%
Expected dividend yield	—		%	—		%	0.37		%
Expected term in years at the date of grant	4.5			4.5			4.5

Stock Options Activity [Table Text Block]

Stock option transactions under the terms of the LTSIP are summarized below:

	Options Outstanding		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
			(per share)		(in years)	(in millions)
Outstanding at December 31, 2016	2,151,957		$	25.26
Granted	418,752		16.77
Forfeited	(14,172	)	15.33
Cancelled	(202,260	)	27.55
Outstanding at December 31, 2017	2,354,277		$	23.62	3.50	$	—
Options Exercisable at December 31, 2017	1,551,861		$	27.90	2.47	$	—
Unvested Options at December 31, 2017	802,416		$	15.33	5.48	$	—

Restricted Share Awards Activity [Table Text Block]

Transactions involving restricted share awards under the terms of the LTSIP are summarized below:

	Restricted Share Awards Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2016	3,208,503		$	14.32
Granted	2,219,763		13.90
Vested	(1,392,043	)	16.53
Forfeited	(314,889	)	14.49
Unvested balance at December 31, 2017	3,721,334		$	13.23

Performance Share Units Activity [Table Text Block]

	Performance Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2016	1,027,280		$	17.24
Granted	405,014		16.90
Vested and paid	(215,439	)	31.63
Forfeited	(17,519	)	13.88
Unvested balance at December 31, 2017	1,199,336		$	14.59

Restricted Share Units Activity [Table Text Block]

Transactions involving restricted share units under the terms of the LTSIP are summarized below:

	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2016	18,034		$	10.12
Granted	9,924		16.98
Vested	(6,012	)	10.12
Unvested balance at December 31, 2017	21,946		$	13.22

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Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2017

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The following table sets forth changes in the benefit obligations and fair value of plan assets for the Company's Pension Plan, SERP and Medical Plan for the years ended December 31, 2017 and 2016, as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2017 and 2016:

	Pension Plan and SERP benefits						Medical Plan benefits
	2017			2016			2017			2016
Change in benefit obligation	(in millions)
Benefit obligation at January 1,	$	129.2		$	120.3		$	5.4		$	5.2
Service cost	0.8			1.2			—			—
Interest cost	4.7			5.2			0.1			0.2
Curtailments	(0.3		)	—			—			—
Benefit payments	(6.9		)	(7.8		)	(0.1		)	(0.4		)
Plan amendments	—			—			(2.4		)	—
Actuarial loss (gain)	2.5			10.3			(0.1		)	0.4
Benefit obligation at December 31,	$	130.0		$	129.2		$	2.9		$	5.4
Change in plan assets
Fair value of plan assets at January 1,	$	86.1		$	79.3		$	—		$	—
Actual return on plan assets	15.3			7.4			—			—
Company contributions to the plan	6.0			7.2			0.1			0.4
Benefit payments	(6.9		)	(7.8		)	(0.1		)	(0.4		)
Fair value of plan assets at December 31,	100.5			86.1			—			—
Underfunded status (current and long-term)	$	(29.5	)	$	(43.1	)	$	(2.9	)	$	(5.4	)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	$	(1.5	)	$	(2.5	)	$	(0.2	)	$	(0.3	)
Other long-term liabilities	(27.9		)	(40.6		)	(2.6		)	(5.1		)
Total amount recognized in balance sheet	$	(29.4	)	$	(43.1	)	$	(2.8	)	$	(5.4	)
Amounts recognized in AOCI
Net actuarial loss (gain)	$	15.0		$	23.5		$	(0.5	)	$	(0.4	)
Prior service cost	1.2			2.9			(1.2		)	1.0
Total amount recognized in AOCI	$	16.2		$	26.4		$	(1.7	)	$	0.6

Pension and Other Postretirement Benefit Costs

The following table sets forth the Company's Pension Plan, SERP and Medical Plan cost and amounts recognized in other comprehensive income (before tax) for the respective years ended December 31:

	Pension Plan and SERP benefits									Medical Plan benefits
	2017			2016			2015			2017			2016			2015
Components of net periodic benefit cost	(in millions)
Service cost	$	0.8		$	1.2		$	2.1		$	—		$	—		$	—
Interest cost	4.7			5.2			4.9			0.1			0.2			0.2
Expected return on plan assets	(5.4		)	(5.6		)	(5.7		)	—			—			—
Curtailment loss	0.7			—			11.2			—			—			—
Settlements	0.2			—			—			—			—			—
Amortization of prior service costs	1.0			1.1			1.7			(0.3		)	0.2			0.2
Amortization of actuarial loss	0.5			0.8			0.5			(0.1		)	—			—
Periodic expense	$	2.5		$	2.7		$	14.7		$	(0.3	)	$	0.4		$	0.4
Components recognized in accumulated other comprehensive income
Current period prior service cost	$	(0.7	)	$	—		$	0.9		$	(2.5	)	$	—		$	—
Current period actuarial (gain) loss	(7.5		)	8.5			2.2			(0.1		)	0.4			(1.4		)
Amortization of prior service cost	(1.0		)	(1.1		)	(12.9		)	0.3			(0.2		)	(0.2		)
Amortization of actuarial gain (loss)	(0.5		)	(0.8		)	(0.5		)	0.1			—			—
Loss on curtailment in current period	(0.3		)	—			(7.1		)	—			—			—
Settlements	(0.2		)	—			—			—			—			—
Total amount recognized in accumulated other comprehensive income	$	(10.2	)	$	6.6		$	(17.4	)	$	(2.2	)	$	0.2		$	(1.6	)

Schedule of Assumptions Used [Table Text Block]

Following are the weighted-average assumptions (weighted by the plan level benefit obligation for pension benefits) used by the Company to calculate the Pension Plan, SERP and Medical Plan obligations at December 31, 2017 and 2016:

	Pension Plan and SERP benefits				Medical Plan benefits
	2017		2016		2017		2016
Discount rate	3.52	%	3.96	%	3.60	%	4.10	%
Rate of increase in compensation(1)	3.50	%	3.50	%	n/a		3.50	%

_______________________

⁽¹⁾   The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the years ended December 31, 2017 and 2016, the rate of increase in compensation only includes the SERP and Medical Plan.

The discount rate assumptions used by the Company represents an estimate of the interest rate at which the Pension Plan, SERP and Medical Plan obligations could effectively be settled on the measurement date.

Following are the weighted-average assumptions (weighted by the net period benefit cost for pension benefits) used by the Company in determining the net periodic Pension Plan, SERP and Medical Plan cost for the years ended December 31:

	Pension Plan and SERP benefits						Medical Plan benefits
	2017		2016		2015		2017		2016		2015
Discount rate	4.00	%	4.23	%	3.94	%	4.10	%	4.40	%	4.00	%
Expected long-term return on plan assets	6.00	%	6.50	%	6.75	%	n/a		n/a		n/a
Rate of increase in compensation(1)	3.50	%	4.00	%	4.00	%	3.50	%	4.00	%	4.00	%

_______________________

⁽¹⁾   The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the years ended December 31, 2017 and 2016, the rate of increase in compensation only includes the SERP and Medical Plan.

Defined Benefit Plan, Actual Plan Asset Allocations [Abstract] (Deprecated 2012-01-31)

The following table summarizes investments for which fair value is measured using the NAV per share practical expedient as of December 31, 2017 and 2016, respectively:

	December 31, 2017				December 31, 2016
	Total		Percentage of total		Total		Percentage of total
	(in millions, except percentages)
Cash and short-term investments	$	0.5	—	%	$	3.5	4	%
Equity securities:
Domestic	35.0		35	%	39.3		46	%
International	15.3		15	%	21.6		25	%
Fixed income	49.7		50	%	21.7		25	%
Total investments	$	100.5	100	%	$	86.1	100	%

Schedule of Expected Benefit Payments [Table Text Block]

Expected Benefit Payments

As of December 31, 2017, the following future benefit payments are expected to be paid:

	Pension Plan and SERP benefits		Medical Plan benefits
	(in millions)
2018	$	6.6	$	0.2
2019	$	8.1	$	0.2
2020	$	7.6	$	0.2
2021	$	8.3	$	0.2
2022	$	6.8	$	0.2
2023 through 2026	$	39.1	$	0.6

Compensation and Employee Benefit Plans [Text Block]

	Year Ended December 31,
	2017		2016		2015
Employees not covered by the Pension Plan or SERP(1)
Maximum employer matching of qualifying earnings	8	%	8	%	8	%
Employees covered by the Pension Plan but not the SERP(1)
Maximum employer matching of qualifying earnings	8	%	8	%	6	%
Employees covered by both the Pension Plan and the SERP(1)
Maximum employer matching of qualifying earnings	6	%	6	%	6	%

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

Details of income tax provisions and deferred income taxes from continuing operations are provided in the following tables.

The components of income tax provisions and benefits were as follows:

	Year Ended December 31,
	2017			2016			2015
Federal income tax provision (benefit)	(in millions)
Current	$	2.1		$	(55.5	)	$	(112.3	)
Deferred	(339.8		)	(614.3		)	34.5
State income tax provision (benefit)
Current	0.5			(1.5		)	(6.6		)
Deferred	25.0			(36.9		)	(9.2		)
Total income tax provision (benefit)	$	(312.2	)	$	(708.2	)	$	(93.6	)

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

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

	Year Ended December 31,
	2017		2016		2015
Federal income taxes statutory rate	35.0	%	35.0	%	35.0	%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit(1)	(40.1	)%	2.4	%	4.2	%
Federal rate change(2)	741.3	%	—	%	—	%
State rate change	2.1	%	(1.1	)%	—	%
Penalties	(0.4	)%	—	%	(0.3	)%
Return to provision adjustment	(0.7	)%	—	%	(0.3	)%
Uncertain tax provision (federal rate change)	(7.7	)%	—	%	—	%
Other	(1.8	)%	—	%	(0.1	)%
Effective income tax rate	727.7	%	36.3	%	38.5	%

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

	December 31,
	2017(1)		2016
Deferred tax liabilities	(in millions)
Property, plant and equipment	$	898.7	$	1,135.0
Deferred tax assets
Net operating loss and tax credit carryforwards	$	308.8	$	161.6
Employee benefits and compensation costs	26.4		49.0
Bonus and vacation accrual	6.2		11.4
Commodity price derivatives	29.9		74.3
Other	9.4		12.8
Total deferred tax assets	380.7		309.1
Net deferred income tax liability	$	518.0	$	825.9
Balance sheet classification
Deferred income tax liability – noncurrent	518.0		825.9
Net deferred income tax liability	$	518.0	$	825.9

Summary of Operating Loss Carryforwards [Table Text Block]

The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2017, are as follows:

	Expiration Dates	Amounts
		(in millions)
State net operating loss and tax credit carryforwards	2018-2037	$	95.8
State net operating loss valuation allowance		$	(56.8	)
U.S. net operating loss	2036-2037	$	250.4
U.S. alternative minimum tax credit	Indefinite	$	19.5

Summary of Positions for which Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Table Text Block]

The following is a reconciliation of our beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2017 and 2016:

	Unrecognized Tax Benefits
	2017		2016
	(in millions)
Balance as of January 1,	$	15.6	$	15.6
Federal benefit of state (change from 35% to 21%)	3.4		—
Balance as of December 31,	$	19.0	$	15.6

As of December 31, 2017 and 2016, QEP had approximately $19.0 million and $15.6 million, respectively, of unrecognized tax benefit that would impact its effective tax rate if recognized. The difference is due to the change in the Federal tax rate in 2017 from 35% to 21%, which affects the federal benefit of the state deduction to the unrecognized tax position.

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Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

The following table provides a summary of unaudited quarterly financial information:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Year
2017	(in millions, except per share amounts or otherwise specified)
Revenues	$	420.1		$	383.7		$	390.1		$	429.0		$	1,622.9
Operating income (loss)	(5.2		)	(0.9		)	132.1			(24.5		)	101.5
Net income (loss)	76.9			45.4			(3.3		)	150.3			269.3
Net gain (loss) from asset sales and impairment	(0.1		)	19.8			157.1			(42.2		)	134.6
Nonrecurring items in operating income (loss)(1)	—			—			8.2			—			8.2
Per share information
Basic EPS	$	0.32		$	0.19		$	(0.01	)	$	0.62		$	1.12
Diluted EPS	0.32			0.19			(0.01		)	0.62			1.12
Production information
Total equivalent production (Mboe)	13,090.3			13,860.6			14,124.1			12,069.9			53,144.9
Total equivalent production (Bcfe)	78.6			83.2			84.7			72.1			318.6

2016
Revenues	$	261.3		$	333.7		$	382.4		$	399.7		$	1,377.1
Operating income (loss)	(1,379.0		)	(92.1		)	(93.1		)	(36.5		)	(1,600.7		)
Net income (loss)	(863.8		)	(197.0		)	(50.9		)	(133.3		)	(1,245.0		)
Net gain (loss) from asset sales and impairment	(1,181.9		)	(1.6		)	0.3			(6.1		)	(1,189.3		)
Nonrecurring items in operating income (loss)(1)	7.7			—			25.0			—			32.7
Per share information
Basic EPS	$	(4.55	)	$	(0.90	)	$	(0.21	)	$	(0.56	)	$	(5.62	)
Diluted EPS	(4.55		)	(0.90		)	(0.21		)	(0.56		)	(5.62		)
Production information
Total equivalent production (Mboe)	13,776.4			13,882.4			14,445.7			13,675.7			55,780.2
Total equivalent production (Bcfe)	82.7			83.3			86.6			82.1			334.7

____________________________

⁽¹⁾  Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017 and 2016.

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Supplemental Gas and Oil Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

	December 31,
	2017			2016
	(in millions)
Proved properties	$	12,470.9		$	14,232.5
Unproved properties, net	1,095.8			871.5
Total proved and unproved properties	13,566.7			15,104.0
Accumulated depreciation, depletion and amortization	(6,642.9		)	(8,797.7		)
Net capitalized costs	$	6,923.8		$	6,306.3

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

	Year Ended December 31,
	2017		2016		2015
	(in millions)
Proved property acquisitions	$	269.6	$	431.6	$	49.6
Unproved property acquisitions	532.4		208.7		39.8
Other acquisitions	13.2		—		—
Exploration costs (capitalized and expensed)	32.7		13.4		8.7
Development costs	1,189.3		509.2		1,010.3
Total costs incurred	$	2,037.2	$	1,162.9	$	1,108.4

Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]

Following are the results of operations of QEP's oil and gas producing activities, before allocated corporate overhead and interest expenses.

	Year Ended December 31,
	2017			2016			2015
	(in millions)
Revenues	$	1,548.1		$	1,271.0		$	1,390.4
Production costs	675.4			616.7			654.1
Exploration expenses	22.0			1.7			2.7
Depreciation, depletion and amortization	735.1			852.3			870.8
Impairment	72.3			1,194.3			55.6
Total expenses	1,504.8			2,665.0			1,583.2
Income (loss) before income taxes	43.3			(1,394.0		)	(192.8		)
Income tax benefit (expense)	(16.0		)	517.2			70.6
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$	27.3		$	(876.8	)	$	(122.2	)

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

As of December 31, 2017, all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's change in quantities of proved oil, gas and NGL reserves for the years ended December 31, 2015, 2016 and 2017 are as follows:

	Oil		Gas		NGL		Total(13)
	(MMbbl)		(Bcf)		(MMbbl)		(MMboe)
Balance at December 31, 2014	172.5		2,317.2		96.6		655.3
Revisions of previous estimates(1)	(47.0	)	(463.8	)	(55.3	)	(179.6	)
Extensions and discoveries(2)	85.6		467.7		21.8		185.4
Purchase of reserves in place(3)	2.0		3.2		0.6		3.1
Sale of reserves in place(4)	(0.4	)	(34.3	)	(0.2	)	(6.3	)
Production	(19.6	)	(181.1	)	(4.7	)	(54.5	)
Balance at December 31, 2015	193.1		2,108.9		58.8		603.4
Revisions of previous estimates(5)	(9.7	)	412.8		(0.3	)	58.8
Extensions and discoveries(6)	13.0		158.1		3.3		42.6
Purchase of reserves in place(7)	62.7		54.6		11.5		83.3
Sale of reserves in place(8)	(0.2	)	(3.6	)	(0.1	)	(0.9	)
Production	(20.3	)	(177.0	)	(6.0	)	(55.8	)
Balance at December 31, 2016	238.6		2,553.8		67.2		731.4
Revisions of previous estimates(9)	3.7		12.5		(3.1	)	2.7
Extensions and discoveries(10)	59.1		101.9		10.4		86.4
Purchase of reserves in place(11)	46.6		125.5		8.7		76.3
Sale of reserves in place(12)	(7.9	)	(831.2	)	(12.6	)	(159.0	)
Production	(19.6	)	(168.9	)	(5.4	)	(53.1	)
Balance at December 31, 2017	320.5		1,793.6		65.2		684.7
Proved developed reserves
Balance at December 31, 2014	99.3		1,288.4		52.2		366.2
Balance at December 31, 2015	109.7		1,245.3		34.4		351.6
Balance at December 31, 2016	103.2		1,309.8		35.7		357.2
Balance at December 31, 2017	116.0		655.5		27.9		253.1
Proved undeveloped reserves
Balance at December 31, 2014	73.2		1,028.8		44.4		289.1
Balance at December 31, 2015	83.4		863.6		24.4		251.8
Balance at December 31, 2016	135.4		1,244.0		31.5		374.2
Balance at December 31, 2017	204.5		1,138.1		37.3		431.6

___________________________

⁽¹⁾  Revisions of previous estimates in 2015 include: 126.2 MMboe of negative revisions due to lower pricing and 67.2 MMboe of negative revisions unrelated to pricing, partially offset by 13.7 MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and the Uinta Basin.

⁽²⁾  Extensions and discoveries in 2015 increased proved reserves by 185.4 MMboe, primarily related to extensions and discoveries in the Williston Basin of 68.2 MMboe, the Uinta Basin of 53.2 MMboe, and the Permian Basin of 49.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations.

⁽³⁾  Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP operated wells in the Williston and Permian basins as discussed in Note 2 – Acquisitions and Divestitures.

⁽⁴⁾  Sale of reserves in place in 2015 relate to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures.

⁽⁵⁾  Revisions of previous estimates in 2016 include 77.3 MMboe of positive revisions, primarily related to successful workovers in Haynesville/Cotton Valley; reserves associated with increased density wells in areas that have been previously developed on lower density spacing; and 5.5 MMboe of positive performance revisions. These positive revisions were partially offset by 18.5 MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices.

⁽⁶⁾  Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations.

⁽⁷⁾  Purchase of reserves in place in 2016 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.

⁽⁸⁾  Sale of reserves in place in 2016 relates to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures.

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure Price per Unit [Table Text Block]

he following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:

	For the year ended December 31,
	2017		2016		2015
Average benchmark price per unit:
Oil price (per bbl)	$	51.34	$	42.75	$	50.28
Gas price (per MMBtu)	$	2.98	$	2.48	$	2.59

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

he standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below:

	Year Ended December 31,
	2017			2016			2015
	(in millions)
Future cash inflows	$	22,028.9		$	16,239.8		$	15,325.3
Future production costs	(9,074.2		)	(7,789.0		)	(7,389.9		)
Future development costs(1)	(4,726.0		)	(3,432.9		)	(2,202.5		)
Future income tax expenses(2)	(1,439.1		)	(913.4		)	(1,169.3		)
Future net cash flows	6,789.6			4,104.5			4,563.6
10% annual discount for estimated timing of net cash flows	(3,692.3		)	(2,176.5		)	(2,087.3		)
Standardized measure of discounted future net cash flows	$	3,097.3		$	1,928.0		$	2,476.3

Principal Sources of Change in Standardized measure of Discounted Future Net Cash Flows [Table Text Block]

he principal sources of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below:

	Year Ended December 31,
	2017			2016			2015
	(in millions)
Balance at January 1,	$	1,928.0		$	2,476.3		$	5,340.0
Sales of oil, gas and NGL produced, net of production costs	(872.7		)	(654.3		)	(736.3		)
Net change in sales prices and in production (lifting) costs related to future production	1,457.2			(739.4		)	(6,307.8		)
Net change due to extensions and discoveries	556.8			81.8			1,765.7
Net change due to revisions of quantity estimates	9.9			122.7			(1,350.2		)
Net change due to purchases of reserves in place	342.7			256.5			29.7
Net change due to sales of reserves in place	(504.7		)	(4.3		)	(48.8		)
Previously estimated development costs incurred during the period	475.4			374.6			865.0
Changes in estimated future development costs	(283.4		)	(476.5		)	560.7
Accretion of discount	235.7			311.1			752.9
Net change in income taxes	(227.4		)	205.4			1,554.4
Other	(20.2		)	(25.9		)	51.0
Net change	1,169.3			(548.3		)	(2,863.7		)
Balance at December 31,	$	3,097.3		$	1,928.0		$	2,476.3

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Summary of Significant Accounting Policies Cash and Cash Equivalents (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Unrestricted Cash	$ 0.0	$ 443.8
Restricted cash	23.4	21.6
Supplemental Disclosures
Cash paid for interest, net of capitalized interest	134.9	139.1	$ 139.4
Cash paid (refund received) for income taxes, net	(0.3)	(123.5)	487.8
Non-cash investing activities
Change in capital expenditure accrual balance	$ 60.2	$ (32.8)	$ (129.2)

XML

Summary of Significant Accounting Policies Accounts Receivable (Details) - Allowance for Doubtful Accounts [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounts, Notes, Loans and Financing Receivable [Line Items]
Bad Debt Expense	$ (1.0)	$ 1.8	$ 0.5
Allowance for Doubtful Accounts Receivable	$ 1.6	$ 4.8

XML

Summary of Significant Accounting Policies Property, plant and equipment (Details)	12 Months Ended
	Dec. 31, 2017
Building [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	10 years
Building [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	30 years
Leasehold Improvements [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Leasehold Improvements [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	10 years
Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	7 years
Furniture and Fixtures [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	3 years
Furniture and Fixtures [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Life	7 years

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Summary of Significant Accounting Policies Impairment of long-lived assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment	$ 78.9	$ 1,194.3	$ 55.6
Gas storage facility [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	6.5
Pinedale [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		1,164.0
Uinta Basin [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		4.7
Other Northern [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	37.1	3.4	18.4
Louisiana [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	1.0
Permian Basin [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties			0.7
Other Southern [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		0.6	20.2
Proved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	38.1	1,172.7	39.3
Unproved properties [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	29.0	17.9	2.0
Goodwill [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	$ 5.3	$ 3.7	$ 14.3

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Summary of Significant Accounting Policies Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Line Items]
Goodwill	$ 5.3	$ 3.7	$ 14.3
Goodwill [Member]
Goodwill [Line Items]
Impairment of Oil and Gas Properties	$ 5.3	$ 3.7	$ 14.3

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Summary of Significant Accounting Policies Credit Risk (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Concentration Risk, Percentage	59.00%	48.00%	30.00%
Shell Trading Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	14.00%	14.00%
Occidental Energy Marketing [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	13.00%
Andeavor Logistics LP [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	13.00%
BP Energy Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%	10.00%
Plains Marketing LP [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%
Valero Marketing And Supply Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10.00%
No Customer [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			10.00%

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Summary of Significant Accounting Policies Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Changes and Error Corrections [Abstract]
Unrecognized Tax Benefits	$ 19.0	$ 15.6	$ 15.6
Interest Related to Uncertain Tax Positions	$ 0.7	0.7	0.5
Penalties Related to Uncertain Tax Positions		$ 0.6	$ 2.2

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Summary of Significant Accounting Policies Earnings Per Share (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive shares excluded from computation of EPS	0.0	0.1	0.0
Used in basic calculation	240.6	221.7	176.6
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	0.0	0.0	0.0
Average diluted common shares outstanding	240.6	221.7	176.6

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Acquisitions and Divestitures 2017 Permian Basin Acquisition (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) a	Dec. 31, 2016 USD ($)
Business Acquisition [Line Items]
Aggregate purchase price	$ 94.5	$ 54.6
2017 Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Aggregate purchase price	$ 720.7
Net acres of producing and undeveloped oil and gas properties | a	15,100
Additional acquisitions in the Permian Basin [Member]
Business Acquisition [Line Items]
Aggregate purchase price	$ 50.0

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Acquisitions and Divestitures 2016 Permian Basin Acquisition Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) a	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Aggregate purchase price	$ 94.5	$ 54.6
Bargain purchase gain from acquisitions	0.4	(22.6)	$ 0.0
2016 Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Aggregate purchase price	$ 591.0
Net acres of producing and undeveloped oil and gas properties | a	9,600
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	$ 80.2	3.8
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual	221.4	(0.7)
Business Combination, Acquisition Related Costs		$ 2.3
Bargain purchase gain from acquisitions	$ 17.8

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Acquisitions and Divestitures 2016 Permian Basin Purchase Accounting Entries (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Aggregate purchase price	$ 94.5	$ 54.6
2016 Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Aggregate purchase price	591.0
Recognized identifiable assets acquired and liabilities assumed, net	591.0
2016 Permian Basin Acquisition [Member] | Proved Property [Member]
Business Acquisition [Line Items]
Recognized identifiable assets acquired and liabilities assumed, net	406.2
2016 Permian Basin Acquisition [Member] | Unproved Property [Member]
Business Acquisition [Line Items]
Recognized identifiable assets acquired and liabilities assumed, net	214.2
2016 Permian Basin Acquisition [Member] | Asset Retirement Obligation Costs [Member]
Business Acquisition [Line Items]
Recognized identifiable assets acquired and liabilities assumed, net	(11.6)
2016 Permian Basin Acquisition [Member] | Bargain Purchase Gain [Member]
Business Acquisition [Line Items]
Recognized identifiable assets acquired and liabilities assumed, net	$ (17.8)

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Acquisitions and Divestitures 2016 Permian Basin Acquisition Pro Forma Results (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Revenues	$ 429.0	$ 390.1	$ 383.7	$ 420.1	$ 399.7	$ 382.4	$ 333.7	$ 261.3	$ 1,622.9	$ 1,377.1	$ 2,018.6
Net income (loss)	$ 150.3	$ (3.3)	$ 45.4	$ 76.9	$ (133.3)	$ (50.9)	$ (197.0)	$ (863.8)	$ 269.3	$ (1,245.0)	$ (149.4)
Earnings Per Share, Basic	$ 0.62	$ (0.01)	$ 0.19	$ 0.32	$ (0.56)	$ (0.21)	$ (0.90)	$ (4.55)	$ 1.12	$ (5.62)	$ (0.85)
Earnings Per Share, Diluted	$ 0.62	$ (0.01)	$ 0.19	$ 0.32	$ (0.56)	$ (0.21)	$ (0.90)	$ (4.55)	$ 1.12	$ (5.62)	$ (0.85)
2016 Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Revenues										$ 1,377.1
Net income (loss)										$ (1,245.0)
Earnings Per Share, Basic										$ (5.62)
Earnings Per Share, Diluted										$ (5.62)
Business Acquisition, Pro Forma Revenue										$ 1,392.5
Business Acquisition, Pro Forma Net Income (Loss)										$ (1,246.8)
Business Acquisition, Pro Forma Earnings Per Share, Basic										$ (5.62)
Business Acquisition, Pro Forma Earnings Per Share, Diluted										$ (5.62)

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Acquisitions and Divestitures Pinedale Divestiture (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 806.8	$ 29.0	$ 21.8
Gain (Loss) on Disposition of Property Plant Equipment	213.5	5.0	4.6
Long-term Purchase Commitment, Amount	45.0
Results of Operations, Income before Income Taxes	43.3	(1,394.0)	(192.8)
Pinedale Divestiture [Member]
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	718.2
Gain (Loss) on Disposition of Property Plant Equipment	180.4
Results of Operations, Income before Income Taxes	251.0	(1,152.7)	$ (45.6)
Long term [Member]
Divestitures [Line Items]
Purchase Commitment, Remaining Minimum Amount Committed	3.2
Total [Member]
Divestitures [Line Items]
Purchase Commitment, Remaining Minimum Amount Committed	30.6
Short term [Member]
Divestitures [Line Items]
Purchase Commitment, Remaining Minimum Amount Committed	$ 27.4
Pinedale [Member]
Divestitures [Line Items]
Impairment of Oil and Gas Properties		1,164.0
Proved Property [Member] | Pinedale [Member]
Divestitures [Line Items]
Impairment of Oil and Gas Properties		$ 1,164.0

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Acquisitions and Divestitures (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Significant Acquisitions and Disposals [Line Items]
Aggregate purchase price	$ 94.5	$ 54.6
Bargain purchase gain from acquisitions	0.4	(22.6)	$ 0.0
Goodwill	5.3	3.7	14.3
Proceeds from Sale of Oil and Gas Property and Equipment	806.8	29.0	21.8
Gain (Loss) on Disposition of Property Plant Equipment	213.5	5.0	4.6
Central Basin Platform [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	3.5
2015 Divestitures [Member]
Significant Acquisitions and Disposals [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment			(0.9)
Other Northern [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	85.1
Gain (Loss) on Disposition of Property Plant Equipment	$ 33.1
Other Southern [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment		29.0	31.7
Gain (Loss) on Disposition of Property Plant Equipment		8.6	21.0
Other Southern [Member] | Cash [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			21.8
Other Southern [Member] | Accounts Receivable [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			9.9
Other Acquisitions [Member]
Significant Acquisitions and Disposals [Line Items]
Bargain purchase gain from acquisitions		4.4
Williston & Permian Basins [Member]
Significant Acquisitions and Disposals [Line Items]
Goodwill		$ 14.3
Other Northern & Uinta Basin [Member]
Significant Acquisitions and Disposals [Line Items]
Aggregate purchase price			$ 98.3

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Capitalized Exploratory Well Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capitalized Exploratory Well Costs [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 806.8	$ 29.0	$ 21.8
Balance at January 1,	14.2	2.6	12.6
Additions to capitalized exploratory well costs	10.7	11.7	6.0
Reclassifications to proved properties	(3.6)	0.0	(16.0)
Capitalized exploratory well costs charged to expense	21.3	(0.1)	0.0
Impairment	78.9	1,194.3	55.6
Balance at December 31,	0.0	$ 14.2	$ 2.6
Central Basin Platform [Member]
Capitalized Exploratory Well Costs [Line Items]
Reclassifications to proved properties	(3.6)
Impairment	28.3
Central Basin Platform [Member]
Capitalized Exploratory Well Costs [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 3.5

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Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset retirement obligation, current	$ 7.5	$ 5.8
Asset retirement obligations, noncurrent	206.6	225.8
ARO Liability [Roll Forward]
ARO liability, Beginning Balance	231.6	206.8
Accretion	7.7	8.9
Liabilities incurred	23.5	17.0
Revisions of Estimates	8.5	6.5
Liabilities related to assets sold	34.9	0.0
Liabilities settled	(22.3)	(7.6)
ARO liability, Ending Balance	214.1	$ 231.6
2017 Permian Basin Acquisition [Member]
ARO Liability [Roll Forward]
Liabilities incurred	14.2
2016 Permian Basin Acquisition [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Recognized identifiable assets acquired and liabilities assumed, net	(591.0)
ARO Liability [Roll Forward]
Liabilities incurred	11.6
Pinedale Divestiture [Member]
ARO Liability [Roll Forward]
Liabilities related to assets sold	$ (34.9)

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Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Proved properties [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Impairment of Oil and Gas Properties	$ 38.1	$ 1,172.7	$ 39.3

XML

Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Millions		Dec. 31, 2017	Dec. 31, 2016
Financial Assets
Netting Adjustments	[1]	$ (19.4)	$ 0.0
Derivative Asset		3.5	0.0
Financial liabilities
Netting Adjustments	[1]	(19.4)	0.0
Derivative Liability		135.4	201.8
Level 1 [Member]
Financial Assets
Derivative instruments		0.0	0.0
Financial liabilities
Derivative instruments		0.0	0.0
Level 2 [Member]
Financial Assets
Derivative instruments		22.9	0.0
Financial liabilities
Derivative instruments		154.8	201.8
Level 3 [Member]
Financial Assets
Derivative instruments		0.0	0.0
Financial liabilities
Derivative instruments		0.0	0.0
Long term [Member]
Financial Assets
Netting Adjustments	[1]	(2.2)	0.0
Derivative Asset		0.1	0.0
Financial liabilities
Netting Adjustments	[1]	(2.2)	0.0
Derivative Liability		31.8	32.0
Long term [Member] | Level 1 [Member]
Financial Assets
Derivative instruments		0.0	0.0
Financial liabilities
Derivative instruments		0.0	0.0
Long term [Member] | Level 2 [Member]
Financial Assets
Derivative instruments		2.3	0.0
Financial liabilities
Derivative instruments		34.0	32.0
Long term [Member] | Level 3 [Member]
Financial Assets
Derivative instruments		0.0	0.0
Financial liabilities
Derivative instruments		0.0	0.0
Short term [Member]
Financial Assets
Netting Adjustments	[1]	(17.2)	0.0
Derivative Asset		3.4	0.0
Financial liabilities
Netting Adjustments	[1]	(17.2)	0.0
Derivative Liability		103.6	169.8
Short term [Member] | Level 1 [Member]
Financial Assets
Derivative instruments		0.0	0.0
Financial liabilities
Derivative instruments		0.0	0.0
Short term [Member] | Level 2 [Member]
Financial Assets
Derivative instruments		20.6	0.0
Financial liabilities
Derivative instruments		120.8	169.8
Short term [Member] | Level 3 [Member]
Financial Assets
Derivative instruments		0.0	0.0
Financial liabilities
Derivative instruments		$ 0.0	$ 0.0

[1] The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Consolidated Balance Sheets for the contracts that contain netting provisions. Refer to Note 6 – Derivative Contracts for additional information regarding the Company's derivative contracts.

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Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Cash and cash equivalents	$ 0.0	$ 443.8
Cash and cash equivalents, Level 1 Fair Value	0.0	443.8
Checks outstanding in excess of cash balances	44.0	12.3
Checks outstanding in excess of cash balances, Level 1 Fair Value	44.0	12.3
Long-term debt	2,160.8	2,020.9
Long-term debt, Level 1 Fair Value	$ 2,256.2	$ 2,104.3

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Derivative Contracts (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Forecasted production from proved reserves (in hundredths)	100.00%
Expected Annual Production Covered By Derivatives	50.00%
Expected Annual Production Covered By Derivatives, High	75.00%

XML

Derivative Contracts Schedule of Commodity Derivative Contracts (Details) bbl in Millions, MMBTU in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) MMBTU bbl $ / MMBTU $ / bbl
Oil Swaps [Member] | Production [Member] | Year 2018 [Member] | NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	16.8
Underlying, Derivative Asset | $ / bbl	52.48
Oil Swaps [Member] | Production [Member] | Year 2019 [Member] | NYMEX WTI [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	8.0
Underlying, Derivative Asset | $ / bbl	51.78
Gas Swaps [Member] | Production [Member] | Year 2018 (July through December) [Member] | NYMEX HH [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1.8
Underlying, Derivative Asset | $ / MMBTU	3.01
Gas Swaps [Member] | Production [Member] | Year 2018 [Member] | NYMEX HH [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	109.5
Underlying, Derivative Asset | $ / MMBTU	2.99
Gas Swaps [Member] | Production [Member] | Year 2019 [Member] | IFNPCR [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	36.5
Underlying, Derivative Asset | $ / MMBTU	2.88
Gas Swaps [Member] | Storage [Member] | Year 2018 [Member] | IFNPCR [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.6
Underlying, Derivative Asset | $ / MMBTU	3.06
Oil Basis Swaps [Member] | Production [Member] | Year 2018 (July through December) [Member] | NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	0.9
Derivatives, Weighted Average Differential | $	$ (0.71)
Oil Basis Swaps [Member] | Production [Member] | Year 2018 [Member] | NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7.3
Derivatives, Weighted Average Differential | $	$ (1.06)
Oil Basis Swaps [Member] | Production [Member] | Year 2019 [Member] | NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	4.0
Derivatives, Weighted Average Differential | $	$ (0.80)
Gas Basis Swaps [Member] | Production [Member] | Year 2018 [Member] | NYMEX HH less IFNPCR [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7.3
Derivatives, Weighted Average Differential | $	$ (0.16)

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Derivative Contracts Schedule of Derivatives Financial Statement Presentation (Details) - Fair Value, Inputs, Level 2 [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative instruments - assets	$ 22.9	$ 0.0
Derivative instruments - liabilities	154.8	201.8
Short term [Member]
Derivative [Line Items]
Derivative instruments - assets	20.6	0.0
Derivative instruments - liabilities	120.8	169.8
Long term [Member]
Derivative [Line Items]
Derivative instruments - assets	2.3	0.0
Derivative instruments - liabilities	34.0	32.0
Fair Value, Measurements, Recurring [Member]
Derivative [Line Items]
Derivative instruments - assets	22.9	0.0
Derivative instruments - liabilities	154.8	201.8
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Short term [Member]
Derivative [Line Items]
Derivative instruments - assets	20.6	0.0
Derivative instruments - liabilities	120.8	169.8
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Long term [Member]
Derivative [Line Items]
Derivative instruments - assets	2.3	0.0
Derivative instruments - liabilities	$ 34.0	$ 32.0

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Derivative Contracts Gain (Loss) in Statement of Financial Performance (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments		$ (15.5)	$ 134.0	$ 460.9
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		69.9	(367.0)	(183.7)
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	[1]	24.5	(233.0)	277.2
Oil derivative contracts [Member] | Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments		6.8	86.3	353.7
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		(66.2)	(217.2)	(244.9)
Gas derivative contracts [Member] | Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments		(22.3)	44.8	103.4
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		133.6	(145.4)	62.0
Gas derivative contracts [Member] | Storage [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments		0.0	2.9	3.8
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		2.5	(4.4)	(0.8)
Total [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments		54.4	(233.0)	277.2
Pinedale Divestiture [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	[1]	(29.9)	0.0	0.0
Pinedale Divestiture [Member] | Oil derivative contracts [Member] | Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	[1]	(1.3)	0.0	0.0
Pinedale Divestiture [Member] | Gas derivative contracts [Member] | Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	[1]	(23.5)	0.0	0.0
Pinedale Divestiture [Member] | NGL derivative contracts [Member] | Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	[1]	$ (5.1)	$ 0.0	$ 0.0

[1] The unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 2 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations.

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Restructuring Costs (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Denver Restructuring [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs, percentage of reduction	6.00%
Restructuring costs, costs incurred	$ 1.9
Denver Restructuring [Member] | Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs, costs incurred	1.9
Tulsa Office Closure [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs, costs incurred		$ 8.3
Tulsa Office Closure [Member] | Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs, costs incurred	$ 0.6	3.0
Tulsa Office Closure [Member] | Special Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs, costs incurred		$ 5.3

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Debt (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term debt	$ 2,160.8	$ 2,020.9
Loss from early extinguishment of debt	(32.7)	0.0	$ 0.0
Long-term Debt	$ 2,099.3
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	5.25%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum	6.875%
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 89.0	0.0
Long-term Line of Credit	1,250.0
Letters of Credit Outstanding, Amount	1.0	2.8
Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 0.0	134.0
Debt Instrument, Interest Rate, Stated Percentage	6.80%
Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 51.7	136.0
Debt Instrument, Maturity Date	Mar. 01, 2020
Debt Instrument, Interest Rate, Stated Percentage	6.80%
Debt Instrument, Repurchased Face Amount	$ 84.3
Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 397.6	625.0
Debt Instrument, Maturity Date	Mar. 01, 2021
Debt Instrument, Interest Rate, Stated Percentage	6.875%
Debt Instrument, Repurchased Face Amount	$ 227.4
Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 500.0	500.0
Debt Instrument, Interest Rate, Stated Percentage	5.40%
Senior Notes Due 2026 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 500.0	$ 0.0
Debt Instrument, Maturity Date	Mar. 01, 2026
Debt Instrument, Interest Rate, Stated Percentage	5.60%

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Debt Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Total principal amount of debt	$ 2,160.8	$ 2,020.9
Less unamortized discount	(27.5)	(24.1)
Long-term Debt, Excluding Current Maturities	2,160.8	2,020.9
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	89.0	0.0
Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	0.0	134.0
Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	51.7	136.0
Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	397.6	625.0
Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	500.0	500.0
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	650.0	650.0
Senior Notes Due 2026 [Member]
Debt Instrument [Line Items]
Total principal amount of debt	$ 500.0	$ 0.0

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Commitments and Contingencies Other Commitments (Details) $ in Millions	Dec. 31, 2017 USD ($)
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	$ 95.6
Unrecorded Unconditional Purchase Obligation, Due within Two Years	68.4
Unrecorded Unconditional Purchase Obligation, Due within Three Years	54.9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	29.9
Unrecorded Unconditional Purchase Obligation, Due within Five Years	28.3
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 122.5

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Commitments and Contingencies Long-term Operating lease commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating lease commitments [Abstract]
Operating Leases, Rent Expense	$ 9.6	$ 9.1	$ 8.0
Operating Leases, Future Minimum Payments Due, Next Twelve Months	7.0
Operating Leases, Future Minimum Payments, Due in Two Years	7.2
Operating Leases, Future Minimum Payments, Due in Three Years	7.4
Operating Leases, Future Minimum Payments, Due in Four Years	7.4
Operating Leases, Future Minimum Payments, Due in Five Years	7.2
Operating Leases, Future Minimum Payments, Due Thereafter	$ 4.8

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Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 22.4	$ 35.6	$ 34.7
Shares available for future grants	5.0
Share-based compensation	$ 22.4	35.6	34.7
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	2.3	2.3	2.9
Intrinsic value of options exercised			$ 0.1
Tax benefit from equity-based compensation expense	0.2	$ (6.4)
Unrecognized compensation costs	$ 1.6
Weighted average period for recognition of equity-based compensation expense		2 years 15 days
Weighted average grant date fair value	$ 6.44	$ 3.77	$ 6.82
Restricted Share Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 13.90
Share-based compensation expense	$ 24.6	$ 23.7	$ 25.6
Unrecognized compensation costs	$ 19.2
Weighted average period for recognition of equity-based compensation expense	1 year 11 months 26 days
Award vesting period	3 years
Total fair value of stock that vested during the period	$ 18.4	$ 24.3	22.7
Income tax expense (benefit) related to restricted stock compensation			$ (3.2)
Weighted average grant date fair value	$ 13.90	$ 10.50	$ 20.92
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 16.90
Share-based compensation expense	$ (4.5)	$ 9.4	$ 6.2
Unrecognized compensation costs	$ 1.2
Weighted average period for recognition of equity-based compensation expense	1 year 10 months 21 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	$ 5.3	$ 2.8	$ 3.1
Weighted average grant date fair value	$ 16.90	$ 10.16	$ 21.69
Restricted Share Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 16.98	$ 10.12
Share-based compensation expense	$ 0.0	$ 0.2	$ 0.0
Unrecognized compensation costs	$ 0.1
Weighted average period for recognition of equity-based compensation expense	1 year 11 days

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Share-Based Compensation Schedule of Share-based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Expense [Line Items]
Share-based compensation expense	$ 22.4	$ 35.6	$ 34.7
Stock Options [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	2.3	2.3	2.9
Restricted Share Awards [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	24.6	23.7	25.6
Performance Share Units [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	(4.5)	9.4	6.2
Restricted Share Units (RSUs) [Member]
Share-based Compensation Expense [Line Items]
Share-based compensation expense	$ 0.0	$ 0.2	$ 0.0

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Share-Based Compensation Fair Value of Options Granted and Major Assumptions Used (Details) - Stock Options [Member] - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value	$ 6.44	$ 3.77	$ 6.82
Risk free interest rate, minimum	1.66%	0.99%	1.38%
Risk free interest rate, maximum	1.81%	1.15%	1.38%
Weighted average risk-free interest rate	1.80%	1.20%	1.40%
Expected price volatility range, minimum	43.80%	43.42%	36.80%
Expected price volatility range, maximum	46.70%	43.66%	36.80%
Weighted average expected price volatility	43.90%	43.40%	36.80%
Expected dividend yield	0.00%	0.00%	0.37%
Expected term in years at the date of grant	4 years 6 months	4 years 6 months	4 years 6 months

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Share-Based Compensation Schedule of Stock Option Transactions (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Stock options outstanding, beginning of year | shares	2,151,957
Options granted | shares	418,752
Options forfeited | shares	(14,172)
Options Cancelled | shares	(202,260)
Stock options outstanding, end of year | shares	2,354,277
Options exercisable, shares | shares	1,551,861
Unvested options, shares | shares	802,416
Share-based Compensation Arrangement by Share-based Payment Award, Additional General Disclosures [Abstract]
Weighted average exercise price, beginning of year | $ / shares	$ 25.26
Weighted average exercise price, granted in period | $ / shares	16.77
Weighted average exercise price, forfeited in period | $ / shares	15.33
Weighted average exercise price, cancelled in period | $ / shares	27.55
Weighted average exercise price, end of year | $ / shares	23.62
Options exercisable, weighted average exercise price | $ / shares	27.90
Unvested options, weighted average exercise price | $ / shares	$ 15.33
Weighted average remaining contractual term, options outstanding	3 years 6 months
Weighted average remaining contractual term, options exercisable	2 years 5 months 21 days
Weighted average remaining contractual term, options unvested	5 years 5 months 24 days
Aggregate intrinsic value, options outstanding | $	$ 0.0
Aggregate intrinsic value, options exercisable | $	0.0
Aggregate intrinsic value, options unvested | $	$ 0.0

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Share-Based Compensation Schedule of Restricted Stock Transactions (Details) - Restricted Share Awards [Member]	12 Months Ended
	Dec. 31, 2017 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested balance at beginning of period | shares	3,208,503
Shares granted | shares	2,219,763
Shares vested | shares	(1,392,043)
Shares forfeited | shares	(314,889)
Unvested balance at end of period | shares	3,721,334
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Weighted average grant date fair value, beginning of period | $ / shares	$ 14.32
Weighted average grant date fair value, grants | $ / shares	13.90
Weighted average grant date fair value, vested | $ / shares	16.53
Weighted average grant date fair value, forfeited | $ / shares	14.49
Weighted average grant date fair value, end of period | $ / shares	$ 13.23

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Share-Based Compensation Schedule of Performance Share Unit Transactions (Details) - Performance Share Units [Member]	12 Months Ended
	Dec. 31, 2017 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested balance at beginning of period | shares	1,027,280
Shares granted | shares	405,014
Shares vested and paid out | shares	(215,439)
Shares forfeited | shares	(17,519)
Unvested balance at end of period | shares	1,199,336
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Weighted average grant date fair value, beginning of period | $ / shares	$ 17.24
Weighted average grant date fair value, grants | $ / shares	16.90
Weighted average grant date fair value, vested and paid out | $ / shares	31.63
Weighted average grant date fair value, forfeited | $ / shares	13.88
Weighted average grant date fair value, end of period | $ / shares	$ 14.59

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Share-Based Compensation Schedule of Restricted Share Unit Transactions (Details) - Restricted Share Units (RSUs) [Member] - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested balance at beginning of period	18,034
Shares granted	9,924
Shares vested	(6,012)
Unvested balance at end of period	21,946	18,034
Weighted average grant date fair value, beginning of period	$ 10.12
Weighted average grant date fair value, grants	16.98	$ 10.12
Weighted average grant date fair value, vested	10.12
Weighted average grant date fair value, end of period	$ 13.22	$ 10.12

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Employee Benefits (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	$ 128.7	$ 124.5
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Contributions by Employer	4.0
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	4.0
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 0.4
Defined Benefit Plan, Curtailment loss			$ 11.2
Pension Plan [Member] | Active Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Number of Employees Covered	30
Defined Benefit Plan, Percentage Of Employees Covered	5.00%
Pension Plan [Member] | Non-active Employees [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Number of Employees Covered	184
Pension Plan and SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Contributions by Employer	$ 6.0	7.2
Defined Benefit Plan, Curtailment loss	0.7	0.0	11.2
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year	$ 1.9
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Number of Eligible	17
Defined Benefit Plan, Contributions by Employer	$ 0.1	0.4
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	0.3
Defined Benefit Plan, Curtailment loss	0.0	$ 0.0	$ 0.0
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year	(0.3)
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Contributions by Employer	2.0
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	0.7
Defined Benefit Plan, Curtailment loss	$ 0.7

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Employee Benefits Schedule of Changes in Benefit Obligations and Fair Value of Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Change in plan assets
Fair value of plan assets at January 1,	$ 86.1
Fair value of plan assets at December 31,	100.5	$ 86.1
Pension Plan and SERP [Member]
Change in benefit obligation
Benefit obligation at January 1,	129.2	120.3
Service cost	0.8	1.2	$ 2.1
Interest cost	4.7	5.2	4.9
Curtailments	(0.3)	0.0
Benefit payments	(6.9)	(7.8)
Plan amendments	0.0	0.0
Actuarial loss (gain)	2.5	10.3
Benefit obligation at December 31,	130.0	129.2	120.3
Change in plan assets
Fair value of plan assets at January 1,	86.1	79.3
Actual return on plan assets	15.3	7.4
Company contributions to the plan	6.0	7.2
Benefit payments	(6.9)	(7.8)
Fair value of plan assets at December 31,	100.5	86.1	79.3
Underfunded status (current and long-term)	(29.5)	(43.1)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	(1.5)	(2.5)
Other long-term liabilities	(27.9)	(40.6)
Total amount recognized in balance sheet	(29.4)	(43.1)
Amounts recognized in AOCI
Net actuarial loss (gain)	15.0	23.5
Prior service cost	1.2	2.9
Total amount recognized in AOCI	16.2	26.4
Medical Plan [Member]
Change in benefit obligation
Benefit obligation at January 1,	5.4	5.2
Service cost	0.0	0.0	0.0
Interest cost	0.1	0.2	0.2
Curtailments	0.0	0.0
Benefit payments	(0.1)	(0.4)
Plan amendments	(2.4)	0.0
Actuarial loss (gain)	(0.1)	0.4
Benefit obligation at December 31,	2.9	5.4	5.2
Change in plan assets
Fair value of plan assets at January 1,	0.0	0.0
Actual return on plan assets	0.0	0.0
Company contributions to the plan	0.1	0.4
Benefit payments	(0.1)	(0.4)
Fair value of plan assets at December 31,	0.0	0.0	$ 0.0
Underfunded status (current and long-term)	(2.9)	(5.4)
Amounts recognized in balance sheets
Accounts payable and accrued expenses	(0.2)	(0.3)
Other long-term liabilities	(2.6)	(5.1)
Total amount recognized in balance sheet	(2.8)	(5.4)
Amounts recognized in AOCI
Net actuarial loss (gain)	(0.5)	(0.4)
Prior service cost	(1.2)	1.0
Total amount recognized in AOCI	$ (1.7)	$ 0.6

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Employee Benefits Schedule of Net Periodic Benefit Cost and Other Comprehensive Income for Pension and Other Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plan and SERP [Member]
Components of net periodic benefit cost
Service cost	$ 0.8	$ 1.2	$ 2.1
Interest cost	4.7	5.2	4.9
Expected return on plan assets	(5.4)	(5.6)	(5.7)
Curtailment loss	0.7	0.0	11.2
Settlements	0.2	0.0	0.0
Amortization of prior service costs	1.0	1.1	1.7
Amortization of actuarial loss	0.5	0.8	0.5
Periodic expense	2.5	2.7	14.7
Components recognized in accumulated other comprehensive income
Current period prior service cost	(0.7)	0.0	0.9
Current period actuarial (gain) loss	(7.5)	8.5	2.2
Amortization of prior service cost	(1.0)	(1.1)	(12.9)
Amortization of actuarial gain (loss)	(0.5)	(0.8)	(0.5)
Loss on curtailment in current period	(0.3)	0.0	(7.1)
Settlements	(0.2)	0.0	0.0
Total amount recognized in accumulated other comprehensive income	(10.2)	6.6	(17.4)
Medical Plan [Member]
Components of net periodic benefit cost
Service cost	0.0	0.0	0.0
Interest cost	0.1	0.2	0.2
Expected return on plan assets	0.0	0.0	0.0
Curtailment loss	0.0	0.0	0.0
Settlements	0.0	0.0	0.0
Amortization of prior service costs	(0.3)	0.2	0.2
Amortization of actuarial loss	0.1	0.0	0.0
Periodic expense	(0.3)	0.4	0.4
Components recognized in accumulated other comprehensive income
Current period prior service cost	(2.5)	0.0	0.0
Current period actuarial (gain) loss	(0.1)	0.4	(1.4)
Amortization of prior service cost	0.3	(0.2)	(0.2)
Amortization of actuarial gain (loss)	0.1	0.0	0.0
Loss on curtailment in current period	0.0	0.0	0.0
Settlements	0.0	0.0	0.0
Total amount recognized in accumulated other comprehensive income	$ (2.2)	$ 0.2	$ (1.6)

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Employee Benefits Schedule of Weighted Average Actuarial Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Costs (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plan and SERP [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate used in calculating benefit obligation	3.52%	3.96%
Rate of increase in compensation used for calculating benefit obligation	3.50%	3.50%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate used in calculating net periodic benefit cost	4.00%	4.23%	3.94%
Expected long-term return on plan assets used in calculating net periodic benefit cost	6.00%	6.50%	6.75%
Rate of increase in compensation used in calculating net periodic benefit cost	3.50%	4.00%	4.00%
Medical Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate used in calculating benefit obligation	3.60%	4.10%
Rate of increase in compensation used for calculating benefit obligation		3.50%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate used in calculating net periodic benefit cost	4.10%	4.40%	4.00%
Rate of increase in compensation used in calculating net periodic benefit cost	3.50%	4.00%	4.00%

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Employee Benefits Schedule of Fair Values of Pension and Postretirement Benefit Assets by Asset Class (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 100.5	$ 86.1
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Cash and short-term investments [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 0.5	$ 3.5
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	4.00%
Domestic equity securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 35.0	$ 39.3
Defined Benefit Plan, Actual Plan Asset Allocations	35.00%	46.00%
International equity securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 15.3	$ 21.6
Defined Benefit Plan, Actual Plan Asset Allocations	15.00%	25.00%
Fixed income securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 49.7	$ 21.7
Defined Benefit Plan, Actual Plan Asset Allocations	50.00%	25.00%

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Employee Benefits Schedule of Expected Benefit Payments for Pension and Other Postretirement Benefits (Details) $ in Millions	Dec. 31, 2017 USD ($)
Pension Plan and SERP [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2018	$ 6.6
2019	8.1
2020	7.6
2021	8.3
2022	6.8
2023 through 2026	39.1
Medical Plan [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
2018	0.2
2019	0.2
2020	0.2
2021	0.2
2022	0.2
2023 through 2026	$ 0.6

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Employee Benefits EIP (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	8.00%	8.00%	8.00%
Employee Investment Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized	$ 6.0	$ 5.6	$ 6.3
Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	8.00%	8.00%	6.00%
SERP [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	6.00%	6.00%	6.00%

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Income Taxes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Valuation Allowance [Line Items]
Federal income tax rate		35.00%
Operating Loss Carryforwards, Valuation Allowance		$ 56.8
Alternative minimum tax		19.5
Balance as of December 31,		19.0	$ 15.6	$ 15.6
Interest Related to Uncertain Tax Positions		0.7	0.7	0.5
Penalties Related to Uncertain Tax Positions			$ 0.6	$ 2.2
Louisiana [Member]
Valuation Allowance [Line Items]
Operating Loss Carryforwards, Valuation Allowance		$ 31.8
Subsequent Event [Member]
Valuation Allowance [Line Items]
Federal income tax rate	21.00%

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Income Taxes Schedule of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Federal income tax provision (benefit)
Current	$ 2.1	$ (55.5)	$ (112.3)
Deferred	(339.8)	(614.3)	34.5
State income tax provision (benefit)
Current	0.5	(1.5)	(6.6)
Deferred	25.0	(36.9)	(9.2)
Total income tax provision (benefit)	$ (312.2)	$ (708.2)	$ (93.6)

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Income Taxes Reconciliation of Statutory Federal Income Tax Rate and Effective Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Investments, Owned, Federal Income Tax Note [Line Items]
Federal income tax rate		35.00%
Valuation allowance		$ 36.2
Federal income taxes statutory rate		35.00%	35.00%	35.00%
Increase (decrease) in rate as a result of:
State income taxes, net of federal income tax benefit(1)		(40.10%)	2.40%	4.20%
Federal rate change(2)		741.30%	0.00%	0.00%
State rate change		2.10%	(1.10%)	0.00%
Penalties		(0.40%)	0.00%	(0.30%)
Return to provision adjustment		(0.70%)	0.00%	(0.30%)
Uncertain tax provision (federal rate change)		(7.70%)	0.00%	0.00%
Other		(1.80%)	0.00%	(0.10%)
Effective income tax rate		727.70%	36.30%	38.50%
Subsequent Event [Member]
Investments, Owned, Federal Income Tax Note [Line Items]
Federal income tax rate	21.00%

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Income Taxes Schedule of Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Deferred tax liabilities
Property, plant and equipment	$ 898.7	$ 1,135.0
Deferred tax assets
Net operating loss and tax credit carryforwards	308.8	161.6
Employee benefits and compensation costs	26.4	49.0
Bonus and vacation accrual	6.2	11.4
Commodity price derivatives	29.9	74.3
Other	9.4	12.8
Total deferred tax assets	380.7	309.1
Net deferred income tax liability	518.0	825.9
Balance sheet classification
Deferred income tax liability – noncurrent	518.0	$ 825.9
Net deferred income tax liability	307.9
Change [Member]
Balance sheet classification
Net deferred income tax liability	$ 318.0

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Income Taxes Amounts and Expiration Dates of Net Operating Loss and Tax Credit Carryforwards (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Operating Loss Carryforwards [Line Items]
State net operating loss and tax credit carryforwards	$ 95.8
State net operating loss valuation allowance	(56.8)
U.S. net operating loss	250.4
U.S. alternative minimum tax credit	$ 19.5
State [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards Minimum Expiration Date	2018
Operating Loss Carryforwards Maximum Expiration Date	2034
U.S. (Federal) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards Minimum Expiration Date	2036
Operating Loss Carryforwards Maximum Expiration Date	2037

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Income Taxes Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Balance as of January 1,	$ 15.6	$ 15.6
Federal benefit of state (change from 35% to 21%)	3.4	0.0
Balance as of December 31,	$ 19.0	$ 15.6

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Quarterly Financial Information (Unaudited) (Details) $ / shares in Units, $ in Millions, Bcfe in Billions		3 Months Ended								12 Months Ended
		Dec. 31, 2017 USD ($) Bcfe MBoe $ / shares	Sep. 30, 2017 USD ($) Bcfe MBoe $ / shares	Jun. 30, 2017 USD ($) Bcfe MBoe $ / shares	Mar. 31, 2017 USD ($) Bcfe MBoe $ / shares	Dec. 31, 2016 USD ($) Bcfe MBoe $ / shares	Sep. 30, 2016 USD ($) Bcfe MBoe $ / shares	Jun. 30, 2016 USD ($) Bcfe MBoe $ / shares	Mar. 31, 2016 USD ($) Bcfe MBoe $ / shares	Dec. 31, 2017 USD ($) Bcfe MBoe $ / shares	Dec. 31, 2016 USD ($) Bcfe MBoe $ / shares	Dec. 31, 2015 USD ($) $ / shares
Quarterly Financial Information Disclosure [Line Items]
Revenues		$ 429.0	$ 390.1	$ 383.7	$ 420.1	$ 399.7	$ 382.4	$ 333.7	$ 261.3	$ 1,622.9	$ 1,377.1	$ 2,018.6
Operating income (loss)		(24.5)	132.1	(0.9)	(5.2)	(36.5)	(93.1)	(92.1)	(1,379.0)	101.5	(1,600.7)	(364.5)
Net income (loss)		150.3	(3.3)	45.4	76.9	(133.3)	(50.9)	(197.0)	(863.8)	269.3	(1,245.0)	$ (149.4)
Net gain (loss) from asset sales and impairment		(42.2)	157.1	19.8	(0.1)	(6.1)	0.3	(1.6)	(1,181.9)	134.6	(1,189.3)
Nonrecurring items in operating income (loss)(1)	[1]	$ 0.0	$ 8.2	$ 0.0	$ 0.0	$ 0.0	$ 25.0	$ 0.0	$ 7.7	$ 8.2	$ 32.7
Basic | $ / shares		$ 0.62	$ (0.01)	$ 0.19	$ 0.32	$ (0.56)	$ (0.21)	$ (0.90)	$ (4.55)	$ 1.12	$ (5.62)	$ (0.85)
Diluted | $ / shares		$ 0.62	$ (0.01)	$ 0.19	$ 0.32	$ (0.56)	$ (0.21)	$ (0.90)	$ (4.55)	$ 1.12	$ (5.62)	$ (0.85)
Total equivalent production (Mboe) | MBoe		12,069,900	14,124,100	13,860,600	13,090,300	13,675,700	14,445,700	13,882,400	13,776,400	53,144,900	55,780,200
Total equivalent production (Bcfe) | Bcfe		72.1	84.7	83.2	78.6	82.1	86.6	83.3	82.7	318.6	334.7

[1] Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017 and 2016.

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Supplemental Gas and Oil Information (Unaudited) Capitalized costs (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Capitalized Costs, Oil and Gas Producing Activities, Net [Abstract]
Proved properties	$ 12,470.9	$ 14,232.5
Unproved properties, net	1,095.8	871.5
Total proved and unproved properties	13,566.7	15,104.0
Accumulated depreciation, depletion and amortization	(6,642.9)	(8,797.7)
Net capitalized costs	$ 6,923.8	$ 6,306.3

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Supplemental Gas and Oil Information (Unaudited) Costs incurred (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Abstract]
Accrued capital costs included in development costs	$ 60.6
ARO additions and revisions	32.0
Costs incurred related to the development of proved undeveloped reserves	389.3	$ 258.1	$ 490.4
Proved property acquisitions	269.6	431.6	49.6
Unproved property acquisitions	532.4	208.7	39.8
Other acquisitions	13.2	0.0	0.0
Exploration costs (capitalized and expensed)	32.7	13.4	8.7
Development costs	1,189.3	509.2	1,010.3
Total costs incurred	$ 2,037.2	$ 1,162.9	$ 1,108.4

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Supplemental Gas and Oil Information (Unaudited) Results of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Results of Operations, Income before Income Taxes [Abstract]
Revenues	$ 1,548.1	$ 1,271.0	$ 1,390.4
Production costs	675.4	616.7	654.1
Exploration expenses	22.0	1.7	2.7
Depreciation, depletion and amortization	735.1	852.3	870.8
Impairment	72.3	1,194.3	55.6
Total expenses	1,504.8	2,665.0	1,583.2
Income (loss) before income taxes	43.3	(1,394.0)	(192.8)
Income tax benefit (expense)	(16.0)	517.2	70.6
Results of operations from producing activities excluding allocated corporate overhead and interest expenses	$ 27.3	$ (876.8)	$ (122.2)

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Supplemental Gas and Oil Information (Unaudited) Estimated Quantities of Proved Gas and Oil Reserves (Details) MMBoe in Millions, MMBbls in Millions, Bcf in Billions		12 Months Ended
		Dec. 31, 2017 MMBoe Bcf MMBbls		Dec. 31, 2016 MMBoe Bcf MMBbls		Dec. 31, 2015 MMBoe Bcf MMBbls
Reserve Quantities [Line Items]
Extensions and discoveries | MMBoe						185.4
Oil [Member]
Reserve Quantities [Line Items]
Proved reserves balance, beginning balance		238.6		193.1		172.5
Revisions of previous estimates		3.7	[1]	(9.7)	[2]	(47.0)	[3]
Extensions and discoveries		59.1	[4]	13.0	[5]	85.6	[6]
Purchase of reserves in place		46.6	[7]	62.7	[8]	2.0	[9]
Sale of reserves in place		(7.9)	[10]	(0.2)	[11]	(0.4)	[12]
Production		(19.6)		(20.3)		(19.6)
Proved reserves balance, ending balance		320.5		238.6		193.1
Proved undeveloped reserves, beginning balance		135.4		83.4		73.2
Proved undeveloped reserve, ending balance		204.5		135.4		83.4
Proved developed reserves, beginning balance		103.2		109.7		99.3
Proved developed reserves, ending balance		116.0		103.2		109.7
Gas [Member]
Reserve Quantities [Line Items]
Proved reserves balance, beginning balance | Bcf		2,553.8		2,108.9		2,317.2
Revisions of previous estimates | Bcf		12.5	[1]	412.8	[2]	(463.8)	[3]
Extensions and discoveries | Bcf		101.9	[4]	158.1	[5]	467.7	[6]
Purchase of reserves in place | Bcf		125.5	[7]	54.6	[8]	3.2	[9]
Sale of reserves in place | Bcf		(831.2)	[10]	(3.6)	[11]	(34.3)	[12]
Production | Bcf		(168.9)		(177.0)		(181.1)
Proved reserves balance, ending balance | Bcf		1,793.6		2,553.8		2,108.9
Proved undeveloped reserves, beginning balance | Bcf		1,244.0		863.6		1,028.8
Proved undeveloped reserve, ending balance | Bcf		1,138.1		1,244.0		863.6
Proved developed reserves, beginning balance | Bcf		1,309.8		1,245.3		1,288.4
Proved developed reserves, ending balance | Bcf		655.5		1,309.8		1,245.3
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved reserves balance, beginning balance		67.2		58.8		96.6
Revisions of previous estimates		(3.1)	[1]	(0.3)	[2]	(55.3)	[3]
Extensions and discoveries		10.4	[4]	3.3	[5]	21.8	[6]
Purchase of reserves in place		8.7	[7]	11.5	[8]	0.6	[9]
Sale of reserves in place		(12.6)	[10]	(0.1)	[11]	(0.2)	[12]
Production		(5.4)		(6.0)		(4.7)
Proved reserves balance, ending balance		65.2		67.2		58.8
Proved undeveloped reserves, beginning balance		31.5		24.4		44.4
Proved undeveloped reserve, ending balance		37.3		31.5		24.4
Proved developed reserves, beginning balance		35.7		34.4		52.2
Proved developed reserves, ending balance		27.9		35.7		34.4
Barrels of oil equivalent production [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, beginning balance | MMBoe	[13]	731.4		603.4		655.3
Revisions of previous estimates | MMBoe	[13]	2.7	[1]	58.8	[2]	(179.6)	[3]
Extensions and discoveries | MMBoe	[13]	86.4	[4]	42.6	[5]	185.4	[6]
Purchase of reserves in place | MMBoe	[13]	76.3	[7]	83.3	[8]	3.1	[9]
Sale of reserves in place | MMBoe	[13]	(159.0)	[10]	(0.9)	[11]	(6.3)	[12]
Production | MMBoe	[13]	(53.1)		(55.8)		(54.5)
Proved developed and undeveloped reserves, ending balance | MMBoe	[13]	684.7		731.4		603.4
Proved undeveloped reserves, beginning balance | MMBoe		374.2		251.8		289.1
Proved undeveloped reserves, ending balance | MMBoe		431.6		374.2		251.8
Proved developed reserves, beginning balance | MMBoe		357.2		351.6		366.2
Proved developed reserves, ending balance | MMBoe		253.1		357.2		351.6
Pricing Revisions [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMBoe		32.0		18.5		126.2
Performance Revisions [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMBoe		2.2		5.5		13.7
Positive revisions [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMBoe		2.7		77.3
Operating Cost Revisions [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMBoe		11.0
Other Revisions [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMBoe						67.2
Development plan change [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMBoe		20.5
Williston Basin [Member]
Reserve Quantities [Line Items]
Extensions and discoveries | MMBoe						68.2
Uinta Basin [Member]
Reserve Quantities [Line Items]
Extensions and discoveries | MMBoe						53.2
Permian Basin [Member]
Reserve Quantities [Line Items]
Extensions and discoveries | MMBoe						49.6

[1] Revisions of previous estimates in 2017 include 2.7 MMboe of positive revisions, primarily related to 32.0 MMboe of positive revisions related to pricing, driven by higher oil, gas and NGL prices and 2.2 MMboe of positive performance revisions. These positive revisions were partially offset by 11.0 MMboe of negative revisions related to higher operating costs and 20.5 MMboe of other revisions primarily from changing to a horizontal development plan from a vertical well development plan in the Uinta Basin and increased longer laterals in Haynesville/Cotton Valley. These negative other revisions are partially offset by positive other revisions from successful infill drilling in Haynesville/Cotton Valley and the Williston Basin.

[2] Revisions of previous estimates in 2016 include 77.3 MMboe of positive revisions, primarily related to successful workovers in Haynesville/Cotton Valley; reserves associated with increased density wells in areas that have been previously developed on lower density spacing; and 5.5 MMboe of positive performance revisions. These positive revisions were partially offset by 18.5 MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices.

[3] Revisions of previous estimates in 2015 include: 126.2 MMboe of negative revisions due to lower pricing and 67.2 MMboe of negative revisions unrelated to pricing, partially offset by 13.7 MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and the Uinta Basin.

[4] Extensions and discoveries in 2017 primarily related to new well completions and associated new PUD locations in the Permian Basin.

[5] Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations.

[6] Extensions and discoveries in 2015 increased proved reserves by 185.4 MMboe, primarily related to extensions and discoveries in the Williston Basin of 68.2 MMboe, the Uinta Basin of 53.2 MMboe, and the Permian Basin of 49.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations.

[7] Purchase of reserves in place in 2017 was primarily related to QEP's 2017 Permian Basin Acquisition and various other acquired oil and gas properties as discussed in Note 2 – Acquisitions and Divestitures.

[8] Purchase of reserves in place in 2016 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.

[9] Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP operated wells in the Williston and Permian basins as discussed in Note 2 – Acquisitions and Divestitures.

[10] Sale of reserves in place in 2017 was primarily related to QEP's Pinedale Divestiture as discussed in Note 2 – Acquisitions and Divestitures.

[11] Sale of reserves in place in 2016 relates to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures.

[12] Sale of reserves in place in 2015 relate to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures.

[13] Generally, gas consumed in operations was excluded from reserves, however, in some cases, produced gas consumed in operations was included in reserves when the volumes replaced fuel purchases.

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Supplemental Gas and Oil Information (Unaudited) Average price per unit (Details)	12 Months Ended
	Dec. 31, 2017 $ / bbl $ / Mcf	Dec. 31, 2016 $ / bbl $ / Mcf	Dec. 31, 2015 $ / bbl $ / Mcf
Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
12 month average first-of the month commodity price | $ / bbl	51.34	42.75	50.28
Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
12 month average first-of the month commodity price | $ / Mcf	2.98	2.48	2.59

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Supplemental Gas and Oil Information (Unaudited) Future Development Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Next Twelve Months	$ 486.5
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Two	710.0
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Three	1,006.2
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Development Costs	4,726.0	$ 3,432.9	$ 2,202.5
Waiting on completion and refracturing [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Development Costs	$ 132.6

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Supplemental Gas and Oil Information (Unaudited) Standardized Measure Of Future Net Cash Flows (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 22,028.9	$ 16,239.8	$ 15,325.3
Future production costs	(9,074.2)	(7,789.0)	(7,389.9)
Future development costs	(4,726.0)	(3,432.9)	(2,202.5)
Future income tax expenses	(1,439.1)	(913.4)	(1,169.3)
Future net cash flows	6,789.6	4,104.5	4,563.6
10% annual discount for estimated timing of net cash flows	(3,692.3)	(2,176.5)	(2,087.3)
Standardized measure of discounted future net cash flows	$ 3,097.3	$ 1,928.0	$ 2,476.3	$ 5,340.0

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Supplemental Gas and Oil Information (Unaudited) Change in Standardized Measure of Future Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Change in Standardized Measure of Future Cash Flows [Abstract]
Beginning Balance	$ 1,928.0	$ 2,476.3	$ 5,340.0
Sales of gas, oil and NGL produced during the period, net of production costs	(872.7)	(654.3)	(736.3)
Net change in sales prices and in production (lifting) costs related to future production	1,457.2	(739.4)	(6,307.8)
Net change due to extensions and discoveries	556.8	81.8	1,765.7
Net change due to revisions of quantity estimates	9.9	122.7	(1,350.2)
Changes due to purchases of reserves in place	342.7	256.5	29.7
Changes due to sales of reserves in place	(504.7)	(4.3)	(48.8)
Previously estimated development costs incurred during the period	475.4	374.6	865.0
Changes in estimated future development costs	(283.4)	(476.5)	560.7
Accretion of discount	235.7	311.1	752.9
Net change in income taxes	(227.4)	205.4	1,554.4
Other	(20.2)	(25.9)	51.0
Net change	1,169.3	(548.3)	(2,863.7)
Ending Balance	$ 3,097.3	$ 1,928.0	$ 2,476.3

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Subsequent Event (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Subsequent Event [Line Items]
Aggregate purchase price	$ 94.5	$ 54.6
Potential Divestitures [Member]
Subsequent Event [Line Items]
Severance Costs	20.0
2017 Permian Basin Acquisition [Member]
Subsequent Event [Line Items]
Aggregate purchase price	720.7
2017 Permian Basin Acquisition [Member] | 2017 Permian Basin Acquisition (Additional) [Member]
Subsequent Event [Line Items]
Aggregate purchase price	$ 36.1