QEP Resources, inc.
Annual Report 2017

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-Ký ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For 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: 303-672-6900Securities registered pursuant to Section 12(b) of the Act:Title of each class Name of each exchange on which registeredCommon stock, $0.01 par value New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: NoneIndicate 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 ýIndicate 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 1934during 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 filingrequirements 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 tobe 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 periodthat 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 bestof 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 Form10-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 anemerging growth company. See definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth" in Rule 12b-2of the Exchange Act. Large accelerated filerý Accelerated filero Non-accelerated filero(Do not check if a smaller reporting company)Smaller reporting companyo Emerging growth companyoIf 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 orrevised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. oIndicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ýState the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which thecommon 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 recentlycompleted 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 REFERENCEPart III is incorporated by reference from the registrant's Definitive Proxy Statement for its 2018 Annual Meeting of Stockholders to be filed, pursuant toRegulation 14A, no later than 120 days after the close of the registrant's fiscal year.TABLE OF CONTENTS PageWhere You Can Find More Information2Forward-Looking Statements2Glossary of Terms6 PART I ITEMS 1 & 2.BUSINESS AND PROPERTIES9ITEM 1A.RISK FACTORS31ITEM 1B.UNRESOLVED STAFF COMMENTS47ITEM 3.LEGAL PROCEEDINGS48ITEM 4.MINE SAFETY DISCLOSURES48 PART II ITEM 5.MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASESOF EQUITY SECURITIES49ITEM 6.SELECTED FINANCIAL DATA52ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS55ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK75ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA77ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE123ITEM 9A.CONTROLS AND PROCEDURES123ITEM 9B.OTHER INFORMATION124 PART III ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE127ITEM 11.EXECUTIVE COMPENSATION127ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERMATTERS127ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE127ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES127 PART IV ITEM 15.EXHIBITS AND FINANCIAL STATEMENTS SCHEDULES127ITEM 16.FORM 10-K SUMMARY1321Where You Can Find More InformationQEP Resources, Inc. (QEP or the Company) files annual, quarterly, and current reports with the U.S. Securities and Exchange Commission (SEC). Thesereports 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 theSEC 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 thatcontains 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 reportsfiled 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 orconnected 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 reportor 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'sCode 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 bywriting or calling QEP, 1050 17th Street, Suite 800, Denver, CO 80265 (telephone number: 303-672-6900).Cautionary Statement Regarding Forward-Looking StatementsThis Annual Report on Form 10-K contains or incorporates by reference information that includes or is based upon "forward-looking statements" within themeaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Exchange Act. Forward-looking statementsgive 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. Weuse words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in connection with adiscussion 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;2•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 of2017;•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 anddrilling 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 capitalinvestments;•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);3•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 anduncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the currenteconomic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of futureperformance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual resultsto 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, aswell as the risk of legal proceedings arising from such matters, whether involving public or private claimants or regulatory investigative orenforcement 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;4•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 Form10-K, in other documents, or on the Company's website to reflect future events or circumstances. All such statements are expressly qualified by thiscautionary statement.5Glossary of TermsAdjusted EBITDA A non-GAAP financial measure which management defines as earnings before interest, income taxes, depreciation, depletion andamortization (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 sealevel.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 standardconditions – 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 justifycompletion 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 for the Northwest Pipeline Corporation Rocky Mountains.M Thousand.MM Million.6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 ofthe minerals.midstream Gas gathering, compression, treating, processing, and transmission assets and activities that are non-jurisdictional. Also includes certain crude oiland 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 sixMcf of natural gas.natural gas liquids (NGL) Liquid hydrocarbons that are extracted from the natural gas stream. NGL products include ethane, propane, butane, naturalgasoline 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 QEPResources 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 likelyas 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 whichthe 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 withreasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operatingmethods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal isreasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must havecommenced 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 newwells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall belimited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliabletechnology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having provedundeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specificcircumstances 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 byapplication of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, thelegal right to produce or a revenue interest in the production.7reservoir An underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriersand 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 theproceeds 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 theleased 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 overridingroyalties, 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 expenditureis 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 andreceive a share of any production, subject to all royalties, other burdens and to all capital costs and operating expenses.8FORM 10-KANNUAL REPORT 2017PART IITEMS 1 and 2. BUSINESS AND PROPERTIESNature of BusinessQEP Resources, Inc. (QEP or the Company) is an independent crude oil and natural gas exploration and production company with operations in two regionsof the United States: the Northern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). Unlessotherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on aconsolidated 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 AgreementsIn 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, theresults of operations for the QEP Field Services Company (QEP Field Services), excluding the retained ownership of Haynesville Gathering, were classified asdiscontinued 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 MarketingCompany (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and saleagreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storageactivities and Haynesville Gathering. As a result, QEP Energy directly markets its own oil, gas and NGL production. While QEP continues to act as an agentfor 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 thisproduction. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had prior to2016.In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic280, Segment Reporting, and determined that QEP had one reportable segment effective January 1, 2016. The Company has recast its financial statements forhistorical periods to reflect the impact of the termination of marketing agreements to show its financial results without segments.Financial and Operating HighlightsDuring 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 expensesassociated with the repayment and used the remainder for general corporate purposes.9StrategiesWe 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.OverviewQEP conducts exploration and production (E&P) activities in several of North America's most important hydrocarbon resource plays. QEP has an inventory ofdeveloped and identified undeveloped drilling locations in the Permian Basin in western Texas, the Williston Basin in North Dakota, Haynesville/CottonValley 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 NGLproduction. Since the beginning of 2012, the Company has made approximately $3.9 billion of acquisitions of oil-weighted properties, spent approximately60% 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 totalproduction compared to 14% in 2011. Additionally, oil and NGL revenue represented 68% of total field-level revenues during 2017 compared to 27% in2011. Approximately 56% of total proved reserves at year-end 2017 were oil and NGL. Consistent with its emphasis on oil-weighted properties, QEP nowreflects its production and reserve amounts in oil equivalent volumes rather than gas equivalent volumes. In February 2018, QEP's Board of Directors hasunanimously approved several strategic initiatives including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valleyand 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 anaggregate purchase price of $720.7 million, subject to post-closing purchase price adjustments. The 2017 Permian Basin Acquisition consists ofapproximately 15,100 acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. In addition, QEP has made offers tovarious persons who own additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the sameterms 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 February2018, 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 firsthalf of 2018. QEP received aggregate proceeds of $806.8 million related to the sales of our Pinedale assets (the Pinedale Divestiture) and other propertiesduring 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, (the2016 Permian Basin Acquisition). The 2016 Permian Basin Acquisition consists of approximately 9,600 net acres in Martin County, Texas, which areprimarily held by production from existing vertical wells. The 2016 Permian Basin Acquisition was funded with proceeds from an equity offering in June2016 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, andrelated 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 oiland NGL volumes to refiners, marketers, midstream service providers and other companies, including some with pipeline facilities near QEP's producingproperties. QEP regularly evaluates counterparty credit risk and may require parental guarantees, letters of credit or prepayment from companies withperceived 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 thegathering, transportation, processing and/or fractionation of these products. In addition, QEP has firm transportation commitments with interstate pipelines tomove its gas volumes to multiple destinations dependent upon market conditions. Disruptions impacting pipelines or other midstream providers' facilitiescan 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 welland the buyer arranges transportation to the ultimate destination.Description of PropertiesNorthern RegionWilliston BasinQEP has 362.0 net productive wells (including its interest in non-operated wells) in the Williston Basin that generate substantial cash flows, which help fundfuture development of the Company's portfolio of assets. QEP has developed a majority of its acreage but continues its drilling program targeting the Bakkenand Three Forks formations. In addition, QEP initiated a refracturing program in the Williston Basin. As of December 31, 2017, QEP had one operated rigdrilling in the Williston Basin.11PinedaleIn September 2017, QEP divested of its Pinedale assets for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to post-closingpurchase 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 theConsolidated Statements of Operations.Uinta BasinThe majority of the Uinta Basin's proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs. In 2017, QEP changed from avertical well development plan to a horizontal well development plan and has a large inventory of remaining future locations. As of December 31, 2017, QEPhad one operated rig drilling in the Uinta Basin.Other NorthernThe 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 BasinQEP has 590.2 net productive wells in the Permian Basin. QEP has multiple targeted formations within its acreage in the Permian Basin and is activelydeveloping oil producing zones, primarily in the Spraberry Shale and Wolfcamp formations. QEP continues to actively acquire acreage in the basin and in2017, acquired approximately 17,000 additional net acres. QEP is utilizing a "tank-style" completion methodology and continues to test additionalformations and evaluate the appropriate ultimate density of its development program. As of December 31, 2017, QEP had six operated rigs drilling in thePermian Basin.Haynesville/Cotton ValleyQEP owns producing and undeveloped properties in Haynesville/Cotton Valley and additional lease rights that cover the overlying Hosston and CottonValley formations. QEP has 507.0 net productive wells, including its interest in non-operated wells, in Haynesville/Cotton Valley. Production is primarilydry gas and QEP has numerous future locations to fully develop its acreage. In addition, the Company began a refracturing program in 2016 and continuedthroughout 2017 and into 2018 on QEP operated wells. As of December 31, 2017, QEP had one operated rig drilling in Haynesville/Cotton Valley.Other SouthernThe remainder of QEP's Southern Region primarily consists of small royalty interests over a few properties.ReservesAt December 31, 2017 and 2016, QEP's estimated proved reserves were approximately 684.7 MMboe and 731.4 MMboe, respectively, of which 98% and97%, 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'sestimated 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 reserves116.0 655.5 27.9 253.1 103.2 1,309.8 35.7 357.2Proved undeveloped reserves204.5 1,138.1 37.3 431.6 135.4 1,244.0 31.5 374.2Total proved reserves320.51,793.6 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 inreserves 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 tablebelow: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 11.12016 731.4 55.8 13.12017 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 PinedaleDivestiture in September 2017. Excluding production volumes from the divested Pinedale assets, the reserve life index is 15.8 years for the yearended 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 GasReporting. 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-monthcommodity prices, adjusted for location and quality differentials, for the prior 12 months (unless contractual arrangements designate the price) to calculateeconomic producibility of reserves and the discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to ProvedReserves. 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 additionalinformation 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 2016Northern Region(MMboe) (% of total) (MMboe) (% of total)Williston Basin146.9 21% 160.2 22%Pinedale— —% 160.7 22%Uinta Basin100.8 15% 106.1 14%Other Northern4.5 1% 12.3 2%Southern Region Permian Basin272.7 40% 147.8 20%Haynesville/Cotton Valley159.8 23% 144.3 20%Other Southern— —% — —%Total proved reserves684.7 100% 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 waspartially 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 2017Permian Basin Acquisition. Williston Basin proved reserves decreased primarily from under performance of wells in our high density pilot test areas. OtherNorthern proved reserves decreased primarily due to property divestitures in 2017. Uinta Basin proved reserves decreased primarily due to changing from avertical well development plan to a horizontal well development plan. Haynesville/Cotton Valley's increase of proved reserves is primarily the result of thesuccessful refracturing program in 2017.13Proved Undeveloped ReservesSignificant changes to PUD reserves that occurred during 2017 are summarized in the table below: 2017 (MMboe)Proved undeveloped reserves at January 1,374.2Transferred to proved developed reserves(36.5)Revisions to previous estimates(26.3)Extensions and discoveries71.8Purchase of reserves in place71.9Sale 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 2017from 2016, however the amount of reserves converted decreased because 16.4 MMboe of PUD reserves were converted in 2016 as a result of installation ofadditional 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 aresummarized in the table below: Planned Transfers to Proved DevelopedReserves in 2017 as of December 31,2016 (PUD conversions) Actual Transfers to ProvedDeveloped Reserves in 2017(PUD conversions) Difference (MMboe)Northern Region Williston Basin10.6 16.3 5.7Pinedale3.2 6.2 3.0Uinta Basin— — —Other Northern— — —Southern Region Permian Basin25.1 16.7 (8.4)Haynesville/Cotton Valley6.5 3.5 (3.0)Other Southern— — —Total45.4 42.7 (2.7)Pinedale(1)(3.2) (6.2) (3.0)Total excluding Pinedale42.2 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 PUDreserves 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 expectedprimarily due to unforeseen drilling delays in the Permian Basin as we continued to refine our "tank-style" development and changes in estimated wellspacing, which led to drilling more unproved locations than initially planned. In both Haynesville/Cotton Valley and Pinedale, we had property divestituresthat 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 yearend 2017 conversions to proved developed reserves. In addition, the PUD reserve conversions in Haynesville/Cotton Valley were lower than plannedconversions due to the delayed arrival of the drilling rig in 2017. These lower than planned PUD conversions were partially offset by a higher PUDconversion 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 initiallydisclosed 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-yeardevelopment plan generally does not contemplate a uniform (i.e. 20% per year) conversion of PUD reserves in all of its producing regions, and PUD reserveconversion 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 in2018, $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 besufficient to cover these estimated future development costs. In addition, QEP estimates that its future development costs relating to wells waiting oncompletion 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 by26.3 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)7.8Positive performance17.7Change 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 longerlaterals in Haynesville/Cotton Valley. These negative revisions related to changes in development plans are partially offset by positive revisions related toadditional increased density locations in the Haynesville/Cotton Valley and the Williston Basin. The 17.7 MMboe positive performance revision is primarilyfrom Haynesville/Cotton Valley's successful refracturing program. In addition, QEP removed 8.7 MMboe of PUD reserves that were no longer in our 2018forecasted 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 newPUD 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 acquiredoil 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 andDivestitures, in Item 8 of Part II of this Annual Report on Form 10-K.Additional DisclosuresRefer 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 informationpertaining 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 forthis 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, andto include the reserves attributable to other owners in such wells.15Third Party Reserve ReportsThe Company retained Ryder Scott Company, L.P. (RSC), independent oil and gas reserve evaluation engineering consultants, to prepare the estimates of allof 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 itsproved reserves as of December 31, 2015. RSC prepared approximately 90% and D&M prepared approximately 10% of the Company's total net provedreserves as of December 31, 2015.Qualifications of Technical Person Preparing Reserve ReportsThe individual at RSC who was responsible for overseeing the preparation of QEP's reserve estimates as of December 31, 2017, is a registered ProfessionalEngineer in the State of Colorado and graduated with a Master's of Science degree in Geological Engineering from the University of Missouri at Rolla in1976. The individual has over 30 years of experience in the petroleum industry, including experience estimating and evaluating petroleum reserves. A moredetailed 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 ofreserves received from RSC is QEP's Director of Corporate Reserves. This individual is a member of the Society of Petroleum Engineers and graduated with aBachelor'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 UsedTo estimate proved reserves, the SEC allows a company to use technologies that have been proved effective by actual production from projects in the samereservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping ofone or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain resultswith consistency and repeatability in the formation being evaluated or in an analogous formation. A variety of methodologies were used to determine QEP'sproved 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 thenused, when available, to further corroborate these reserve estimates. Performance methods include, but may not be limited to, decline curve analysis, whichutilized extrapolations of historical production data available through late 2017, in those cases where such data were considered to be definitive. For wellscurrently producing, forecasts of future production rates are based on historical performance data. If no production decline trend has been established, futureproduction rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. Anestimated 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 estimatingfuture 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 tooffset producing wells. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations thatare not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by QEP. Wells or locationsthat are not currently producing may start producing earlier or later than anticipated in these estimates due to unforeseen factors causing a change in thetiming to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/orrecompleting wells and/or constraints set by regulatory bodies. The future production rates from wells currently on production or wells or locations that arenot currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditionsrelated to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, market demand and/or allowables or otherconstraints 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 EstimatesAt 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. TheCompany's capital expenditure plan includes a development plan for converting PUD reserves. The development plan includes only PUD reserves that theCompany is reasonably certain will be drilled within five years of booking based upon management's evaluation of a number of qualitative and quantitativefactors, including estimated risk-based returns; estimated well density; current commodity pricing and cost forecasts consistent with SEC guidelines; recentdrilling and re-stimulated well results; availability of services, equipment, supplies and personnel; seasonal weather; and changes in drilling and completiontechniques and technology. This process is intended to ensure that PUD reserves are only claimed for locations where a final investment decision has beenmade 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. TheReserves Review Committee meets on a semi-annual basis, including prior to the filing of reserves estimates with the SEC and any public disclosure ofreserve estimates. The Reserves Review Committee reviews data that is submitted by the Director of Corporate Reserves to RSC, including cost and pricingassumptions and reserve reconciliations from the previous reserve determinations. The Director of Corporate Reserves' Annual Reserve Summary Report andthe Reserve Committee's Certification are provided to the Audit Committee annually. The Audit Committee also meets annually with RSC to review thereserves estimation reporting process and disclosures. QEP's Board of Directors (Board) annually reviews the Company's five-year capital expenditure planand 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 intechnology; cost and availability of services, equipment, supplies and personnel; acquisition and divestiture activity; and our current and projected financialcondition and liquidity. Management reviews changes to the development plan with the Audit Committee and the Board quarterly. Changes in thedevelopment plan are also considered by management, the Director of Corporate Reserves and the Reserves Review Committee when reserves are estimatedat 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 initialbooking, QEP reclassifies those PUD reserves to non-proved reserve categories. In addition, PUD locations and reserves may be removed from thedevelopment plan ahead of their five-year life expiration as a result of asset divestitures and acquisitions and associated changes in the priority ofdevelopment within QEP's portfolio of assets.Production, Prices and Production CostsThe following table sets forth the production volumes and field-level prices of oil, gas and NGL produced, and the related production costs, for the yearsended December 31, 2017, 2016 and 2015: Year Ended December 31, 2017 2016 2015Production volumes Oil (Mbbl) 19,620.7 20,293.8 19,582.3Gas (Bcf) 168.9 177.0 181.1NGL (Mbbl) 5,367.3 5,978.8 4,704.3Total equivalent production (Mboe) 53,144.9 55,780.2 54,462.1Total equivalent production (Bcfe) 318.9 334.7 326.8Average field-level price (1) Oil (per bbl) $47.88 $37.90 $42.59Gas (per Mcf) $2.92 $2.36 $2.59NGL (per bbl) $20.85 $13.97 $16.98Production costs (per Boe) Lease operating expense $5.55 $4.03 $4.38Transportation and processing costs 4.61 5.18 5.35Production and property taxes 2.15 1.70 2.16Total 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 2015Oil 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 1,192.7Haynesville/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) 711.5A 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 2015Gas production volumes (Bcf) Northern Region Williston Basin 15.5 15.2 11.3 0.3 3.9Pinedale 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 0.9Haynesville/Cotton Valley 72.9 43.4 43.2 29.5 0.2Other 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 2015NGL production volumes (Mbbl) Northern Region Williston Basin 3,206.1 3,182.7 1,953.4 23.4 1,229.3Pinedale 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) 2.7Southern Region Permian Basin 1,168.5 1,109.9 815.4 58.6 294.5Haynesville/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) 1,274.518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 2015Total production volumes (Mboe) Northern Region Williston Basin 18,140.0 20,370.0 18,709.6 (2,230.0) 1,660.4Pinedale 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 1,644.2Haynesville/Cotton Valley 12,188.7 7,285.5 7,268.0 4,903.2 17.5Other 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) 1,318.1A 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 2015Average 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 $0.04Southern Region$9.52 $10.79 $13.41 $(1.27) $(2.62)Average lease operating and transportation and processingcosts$10.16 $9.21 $9.73 $0.95 $(0.52)Northern RegionWilliston BasinProduction volumes decreased 11% to 18,140.0 Mboe during 2017 compared to 2016, due to a decrease in oil production, which was primarily related toreduced drilling and completion activity during 2017, certain operational issues, under performance of certain wells, and producing well shut-ins associatedwith offset completion activity. The oil production decrease was partially offset by increased gas and NGL production, which was primarily attributable tohigher 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 primarilyattributable to additional ethane recovered combined with higher gas recovery from a midstream provider in 2016. These increases were partially offset by adecrease 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 totalequivalent production.PinedaleProduction volumes decreased 38% to 9,871.7 Mboe during 2017 compared to 2016, primarily due to the divestiture of the Pinedale properties in September2017 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 equivalentproduction.Uinta BasinProduction volumes decreased 24% to 3,605.4 Mboe during 2017 compared to 2016, primarily attributable to declining gas production from existing wellsand 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 wellcompletions 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 equivalentproduction.Other NorthernProduction 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 yearsended December 31, 2016 and 2015, respectively.Southern RegionPermian BasinProduction volumes increased 38% to 8,227.2 Mboe during 2017 compared to 2016, primarily as a result of continued horizontal development activities inthe Spraberry Shale and Wolfcamp formations. QEP began 2017 with three operated drilling rigs in the Permian Basin and ended 2017 with six operateddrilling rigs.Production volumes increased 38% to 5,976.7 Mboe during 2016 compared to 2015, primarily due to continued horizontal development drilling, primarilyin 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 equivalentproduction.Haynesville/Cotton ValleyProduction volumes increased 67% to 12,188.7 Mboe during 2017 compared to 2016, due to a well refracturing program that began in 2016 and continuedthroughout 2017 combined with two new well completions in 2017, partially offset by natural production decline. A QEP-operated drilling rig arrived at theend of the third quarter 2017 and remained active through the end of 2017.20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 SouthernProduction 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 WellsThe 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 NetNorthern Region Williston Basin 893 362.0 — — 893 362.0Pinedale(1) — — — — — —Uinta Basin 1,557 210.3 763 567.0 2,320 777.3Other Northern 29 13.4 109 58.9 138 72.3Southern Region Permian Basin 626 590.2 — — 626 590.2Haynesville/Cotton Valley 1 0.1 857 506.9 858 507.0Other Southern 1 — 58 4.0 59 4.0Total 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 toNote 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 anoil 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 iscounted 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 ofcertain costs by third parties. Once the overriding royalty interests are converted to working interests, these wells are included in the Company's gross and netwell count.21Leasehold AcreageThe following table summarizes developed and undeveloped leasehold acreage in which the Company owns a working interest or mineral interest as ofDecember 31, 2017. "Undeveloped Acreage" includes leasehold interests that already may have been classified as containing proved undeveloped reservesand 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 NetColorado 168,348 113,540 75,549 17,129 243,897 130,669Kansas 47,233 20,879 35,543 12,830 82,776 33,709Louisiana 70,303 62,982 1,231 1,302 71,534 64,284Montana 38,337 14,852 331,005 58,315 369,342 73,167New Mexico 7,620 4,211 24,651 2,476 32,271 6,687North Dakota 208,367 69,861 166,560 54,040 374,927 123,901South Dakota 40 40 203,330 107,551 203,370 107,591Texas 50,441 39,573 22,657 17,279 73,098 56,852Utah 174,242 134,038 184,444 104,037 358,686 238,075Wyoming 87,274 54,660 93,809 56,279 181,083 110,939Other 15,435 4,207 157,822 43,517 173,257 47,724Total 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 ofcommercial quantities of oil and gas regardless of whether such acreage contains proved reserves.Expiring LeaseholdsA 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 arerenewed or drilling or production has occurred on the acreage subject to the lease prior to that date. Leases held by production remain in effect untilproduction ceases. The following table sets forth the gross and net undeveloped acres subject to leases summarized in the preceding table that will expireduring the periods indicated: Undeveloped Acres Expiring Gross NetYear ending December 31, 2018 13,867 12,0242019 9,260 7,3562020 7,868 7,2282021 7,126 6,9692022 and later 19,187 18,468Total 57,308 52,04522Drilling ActivityThe following table summarizes the total number of development and exploratory wells drilled (defined to include the number of wells completed at any timeduring 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 NetYear 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, 2017:23 Operated Completions Non-operated Completions Gross Net Gross NetNorthern Region Williston Basin33 27.8 22 0.4Pinedale20 8.6 — —Uinta Basin— — — —Other Northern— — — — Southern Region Permian Basin66 65.7 — —Haynesville/Cotton Valley2 2.0 12 0.8Other 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 NetNorthern Region Williston Basin1 2 2.0 5 4.7 — — 7 0.1Pinedale— — — — — — — — —Uinta Basin1 1 1.0 1 1.0 — — — —Other Northern— — — — — — — — — Southern Region Permian Basin(1)6 29 28.1 36 36.0 — — — —Haynesville/Cotton Valley1 2 2.0 — — 4 0.1 6 0.4Other 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 rigmobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling where practical. For example, in the Permian BasinQEP utilizes "tank-style" development, in which we drill and complete all wells in a given "tank" before any individual well is turned to production. Incertain 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 ismoved from the location. As a result, multi-well pad drilling delays the completion of wells and the commencement of production. In addition, existing wellsthat offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and wellshut-ins have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells have and continueto impact planned conversion of PUD reserves to proved developed reserves. QEP had 42 gross operated wells waiting on completion as of December 31,2017.24Delivery CommitmentsQEP is a party to various long-term sales commitments for physical delivery of oil and gas with future firm delivery commitments as follows: Delivery CommitmentsPeriod(MMboe)201812.0Thereafter—These commitments are physical delivery obligations with prices based on prevailing index prices for oil and gas at the time of delivery. None of thesecommitments requires the Company to deliver oil or gas produced specifically from any of the Company's properties. The Company believes that itsproduction 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 firmdelivery 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 OtherCommitments, 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 prioritiesor 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.SeasonalityQEP drills and completes wells throughout the year, but adverse weather conditions can impact drilling, completion and field operations, which can impactoverall production volumes. Seasonal anomalies can minimize or exaggerate the impact on these operations, while extreme weather events can materiallyconstrain our operations for short periods of time.Significant CustomersQEP'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 EnergyCompany 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'stotal revenues. During the year ended December 31, 2015, no customer accounted for 10% or more of QEP's total revenues. Management believes that theloss 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 arenumerous 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'scompetition.CompetitionQEP faces competition in every facet of its business, including the acquisition of producing leaseholds, wells and undeveloped leaseholds, the marketing ofoil, gas and NGL products and the procurement of goods, services and labor. The Company's competitors include national oil companies, major integrated oiland gas companies, independent oil and gas companies, individual producers, gas marketers and major pipeline companies, as well as participants in otherindustries supplying energy, fuel and services to consumers.EmployeesAt both December 31, 2017 and 2016, QEP had 656 employees. None of QEP's employees are represented by unions or covered by collective bargainingagreements.25Executive Officers of the RegistrantThe 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 withQuestar Corporation: Chief Operating Officer (2008 to 2010); Executive Vice President and Director (2003to 2010); President, Chief Executive Officer and Director, Market Resources and Market Resourcessubsidiaries (2002 to 2010).Richard J. Doleshek 59 Executive Vice President and Chief Financial Officer (2010 to present). Treasurer (2010 to 2014). ChiefAccounting Officer (2013 to 2014). Previous titles with Questar Corporation: Executive Vice President andChief Financial Officer (2009 to 2010). Prior to joining Questar, Mr. Doleshek was Executive Vice Presidentand 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 andCompletions (2005 to 2008).Christopher K. Woosley 48 Senior Vice President and General Counsel (2017 to present). Vice President and General Counsel (2012 to2016). 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 ofHuman Resources at Suncor Energy USA (2004 to 2010) and held a variety of Human Resources roles inCanada 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/FinancialAnalyst 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 thepleasure of the Company's Board of Directors. There is no arrangement or understanding under which any of the officers were selected.Government RegulationQEP's business operations are subject to a wide range of local, state, tribal and federal statutes, rules, orders and regulations. The regulatory environment inwhich 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 consideredan 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 ActivitiesThe regulation of oil and gas exploration and production activities is a broad and increasingly complex area, notably including laws and regulationsgoverning the potential discharge or release of materials into the environment or otherwise relating to environmental protection. These laws and regulationsinclude, 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 itsbusiness, including, but not limited to, engines, tanks and dehydrators. In 2016, the Environmental Protection Agency (EPA) adopted various regulationsspecific to oil and gas exploration, production, gathering and processing, which impose air quality controls and work practices, and govern sourcedetermination and permitting requirements, and methane emissions. Additionally, many states are adopting air permitting and other air quality controlregulations specific to oil and gas exploration, production, gathering and processing that are more stringent than existing requirements under federalregulations. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection withmaintaining or obtaining operating permits and approvals addressing other air emission-related issues.26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 gasproduction. The FIP primarily impacts QEP's operations on the Fort Berthold Reservation in the Williston Basin and on the Uintah and Ouray IndianReservations in the Uinta Basin. The FIP creates a permit-by-rule process for minor sources that also incorporates emission limits and other requirementsunder various federal air quality standards, applying them to a range of equipment and processes used in oil and gas production. However, the FIP does notapply 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 mayrequire additional emissions controls on existing equipment as a result of expected designation of a portion of the Uinta Basin as a nonattainment area forozone. 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 longerapply 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 themeasurement and annual reporting of carbon dioxide, methane and other greenhouse gases (GHG) emitted from certain large facilities, including onshore oiland gas production, processing, transmission, storage and distribution facilities. In addition, both houses of Congress have considered legislation to reduceemissions of GHG, and a number of states have taken, or are considering taking, legal measures to reduce emissions of GHG, primarily through thedevelopment 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 andcompletions and royalties potentially owed for loss of such emissions from oil and gas facilities producing on federal and tribal leases. Certain provisions ofthe final rule took effect in January 2017 while other provisions had a compliance deadline of January 2018. In December 2017, the BLM delayed theobligations to comply with certain provisions of the rule until January 2019. On February 22, 2018, a United States District Court for the Northern District ofCalifornia preliminarily enjoined the BLM's decision to delay the rule's compliance obligations, requiring QEP and other operators to comply immediatelywith 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 requiringthem to obtain numbers for all onshore points of federal royalty measurement from the BLM, adjusting recordkeeping requirements, and imposing new oiland gas measurement equipment standards, among other requirements, for production from federal and Indian leases. Although these regulations took effectin 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, andother pollutants into regulated "waters of the United States." These laws also require the preparation and implementation of Spill Prevention, Control, andCountermeasure Plans in connection with on-site storage of significant quantities of oil. The scope of what areas constitute jurisdictional waters of theUnited States regulated under the Clean Water Act is currently entangled in ongoing litigation and related administrative matters that are not expected to beresolved 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 regulatedareas much as they have over the last decade. Areas regulated under comparable state laws are generally defined more broadly. The federal Safe DrinkingWater Act (SDWA) and comparable state statutes strictly regulate the disposal, treatment, and release of water produced or used during oil and gasdevelopment, 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 certainwork 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. Thenew nationwide permits took effect in March 2017, or when certified by each state, whichever was later. The oil and gas industry broadly utilizes nationwidepermits 12, 14, and 39 for the construction, maintenance and repairs of pipelines, roads, and drill pads, respectively, and related structures in waters of theUnited 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 theexclusive economic zone of the United States.27Comprehensive Environmental Response, Compensation and Liability Act of 1980. The federal Comprehensive Environmental Response, Compensationand 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 tojoint and several liability for the costs of cleaning up the hazardous substances released into the environment and for damages to natural resources. Suchliability 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" ofhazardous waste or an "owner" or "operator" of a hazardous waste treatment, storage or disposal facility. RCRA and many state counterparts specificallyexclude from the definition of hazardous waste "drilling fluids, produced waters, and other wastes associated with the exploration, development, orproduction of oil, gas or geothermal energy." Any repeal or modification of the oil and gas exploration and production waste exemption would increase thevolume 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 environmentalnongovernmental organizations (ENGOs). The consent decree requires the EPA to review and determine whether it will revise the RCRA regulations forexploration and production waste to treat such waste as hazardous waste. The EPA must complete its review and make its decision regarding revision byMarch 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 July2021.Hydraulic Fracturing Regulations. QEP's current and future production and oil and gas reserves are derived from reservoirs that require hydraulic fracturestimulation to be commercially viable. Hydraulic fracture stimulation involves pumping fluid at high pressure into tight sand or shale reservoirs to artificiallyinduce fractures. The artificially induced fractures allow better connection between the wellbore and the surrounding reservoir rock, thereby enhancing theproductive capacity and ultimate hydrocarbon recovery of each well. The fracture stimulation fluid is typically composed of over 99% water and sand, withthe remaining constituents consisting of chemical additives designed to optimize the fracture stimulation treatment and production from the reservoir. QEPdiscloses the contents of hydraulic fracturing fluids, and submits information regarding its wells and the fluids used in them, to the national online disclosureregistry, 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 andeconomically feasible, QEP recycles flow-back and produced water for use in fracture stimulation, which reduces water consumption from surface andgroundwater sources and reduces produced water disposal volumes. QEP also employs additional measures, when available, to protect water quality such asusing hydrocarbon free lubricants in water well construction, locking all inactive water wells to prevent unauthorized use, and transporting both fresh andproduced water by pipeline instead of truck when feasible to avoid truck traffic and emissions. QEP believes that the employment of fracture stimulationtechnology does not present any significant additional risks other than those associated with the disposal of waste water (see Item 1A - Risk Factors foradditional 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 watersampling, waste handling, and seismic monitoring. Other states rely for this purpose upon their existing regulatory programs for permitting wells, ensuringwellbore integrity, managing waste, and overseeing oil and gas development. States are updating legislative and regulatory requirements for hydraulicfracturing 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 activitiesinvolving diesel fuel under the SDWA, but QEP does not use diesel fuel in any of its hydraulic fracturing fluids. In recent years, the EPA adoptedpretreatment standards under the Clean Water Act for hydraulic fracturing effluent, issued an advance notice of proposed rulemaking under the ToxicSubstances Control Act to obtain data on hydraulic fracturing chemicals, and published a multi-year study on potential impacts to drinking water fromhydraulic fracturing. In 2016, the Occupational Safety and Health Administration (OSHA) adopted employee-protection requirements regarding silica, whichis used in hydraulic fracturing fluids.28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 incurpotentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development orproduction 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 andminerals where QEP operates. These regulations include, but are not limited to, such matters as lease provisions, drilling and production requirements, surfaceuse restrictions, environmental standards, royalty considerations and taxes. In March 2016, the BIA implemented regulations significantly altering theprocedure for obtaining rights-of-way on tribal lands. In certain cases, these new regulations have increased the time and cost required to obtain necessaryrights-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 andNational Environmental Policy Act (NEPA). The Endangered Species Act restricts activities that may affect federally identified endangered and threatenedspecies or their habitats through the implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas. NEPA requires thatfederal agencies assess the direct, indirect and cumulative environmental impacts of their authorizations. This analysis is done in Environmental Assessmentsor Environmental Impact Statements prepared for a lead agency under the Council on Environmental Quality and other agency regulations, usually for theBLM 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 planningcommittees and emergency response departments. In January 2017, the EPA issued proposed rules to add natural gas processing facilities to the list offacilities that must report under EPCRA, which have not been finalized. The federal Occupational Safety and Health Act establishes workplace standards forthe protection of the health and safety of employees, including the implementation of hazard communication programs designed to inform employees abouthazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures.Regulation of Underground StorageQEP, through its wholly owned subsidiary Clear Creek Storage Company, LLC (Clear Creek), operates an underground gas storage facility under thejurisdiction of the FERC. Clear Creek is subject to specific FERC regulations governing interstate transmission facilities and activities, including but notlimited 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 ofjurisdictional natural gas facilities. Regulation is intended to permit the recovery, through rates, of the cost of service, including a return on investment. InDecember 2016, the Pipeline and Hazardous Materials Safety Administration published an Interim Final Rule governing safety at underground natural gasstorage facilities. The rule required adoption of American Petroleum Institute Recommended Practices for depleted reservoir storage facilities by January2018, which was a highly compressed time frame, especially for smaller facilities like Clear Creek.Transportation RegulationsRegulation of the Transportation and Sale of Natural Gas. The FERC regulates the transportation and sale for resale of natural gas in interstate commercepursuant 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 EnergyPolicy 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 toas "non-jurisdictional” gatherer and gathering lines/systems). However, there is no bright-line test for determining jurisdictional status. InHaynesville/Cotton Valley, QEP owns, or holds interests in, a number of pipelines that it asserts are non-jurisdictional gathering lines (under FERCguidelines). However, because there is no bright-line jurisdictional test, the distinction between non-jurisdictional gathering and FERC-regulatedtransmission pipelines may be the subject of disputes and litigation, and the jurisdictional status may change. QEP's gas gathering system is not currentlysubject to state utility regulations.29Regulation of Interstate Crude Oil Pipelines. Some of QEP's crude oil pipelines are subject to regulation by the Texas Railroad Commission (TRRC). Theapplicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipelineproperty used to render services. QEP's crude oil pipelines (specifically the rates, terms and conditions for shipments) may also be subject to FERC regulationif the crude oil is transported in interstate or foreign commerce, whether by QEP's pipelines or other means of transportation (pursuant to the InterstateCommerce 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'spipelines. 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 HazardousMaterials Safety Administration (PHMSA), pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (NGPSA), with respect to natural gas and theHazardous 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 ofTransportation issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on "offerors" ofcrude oil, including sampling, testing and certification requirements to improve classification of energy products placed into transport.State RegulationsThe 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 andaffect 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 rulesrequire companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring andreporting 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. In2016, the TRRC conformed administrative practices and procedures for horizontally drilled and fractured fields to those applicable to other types ofdevelopment.North Dakota. The North Dakota Industrial Commission (the NDI Commission), North Dakota's chief energy regulator, issued an order in June 2014 to reducethe volume of natural gas flared from oil wells in the Bakken and Three Forks formations. In connection with that order, the NDI Commission requiredoperators 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 itwill be processed. Production caps or penalties are imposed on certain wells that cannot meet the capture goals. In addition, pursuant to Commission OrderNo. 25417 we are required to condition crude oil produced in the Bakken Petroleum System to remove lighter, volatile hydrocarbons and reduce the vaporpressure 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 gasactivities. Further, UDEC was concerned there were hundreds of non-compliant oil and gas facilities in operation. To address these issues, the Utah AirQuality Board voted to approve a new Permit by Rule (PBR) proposed by the Utah Division of Air Quality (UDAQ) in January 2018. The PBR (proposedSeptember 6, 2017) requires emission controls for tanks, dehydrators and tank truck loading operations, as well as leak detection and repair and enginerequirements for new sources and existing sources above specific emission thresholds. The PBR also mandates an emission source registration and triennialemissions inventory. In 2016, Utah's Governor and the Ute Tribe made recommendations to the EPA regarding the designation of a portion of the Uinta Basinas nonattainment for the eight-hour ozone National Ambient Air Quality Standard. In December 2017, the EPA responded to Utah and the Ute Tribe'snonattainment recommendation for the Uinta Basin and indicated that the EPA intends to expand the recommended nonattainment area in the Uinta Basin toinclude 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 airquality permitting and additional control of emissions through the permitting programs applicable to QEP, as implemented by the UDEQ and EPA.30Other RegulationsDodd-Frank Wall Street Reform and Consumer Protection Act. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) isdesigned to provide a comprehensive framework for the regulation of the over-the-counter derivatives market with the intent to provide greater transparencyand reduction of risk between counterparties. The Dodd-Frank Act subjects certain participants to capital and margin requirements and requires manyderivative transactions to be cleared on exchanges. The Dodd-Frank Act provides for an exemption from these clearing and cash collateral requirements forcommercial 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 collectingroyalties on gas produced from Federal and Indian lands. In August 2016, the ONRR revised its civil penalty regulations, making it easier for the ONRR toissue 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 significantchanges 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 thelower federal statutory tax rate of 21% compared to 35%. The Tax Legislation also repeals the corporate alternative minimum tax (AMT). Several provisionsof 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 financialstatements. The impact of the Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptionsthe Company has made and actions the Company may take as a result of the Tax Legislation. Additionally, guidance issued by the relevant regulatoryauthorities regarding the Tax Legislation may materially impact QEP's financial statements. The Company will continue to analyze the Tax Legislation todetermine the full impact of the new law, on the Company's consolidated financial statements and operations.ITEM 1A. RISK FACTORSDescribed below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. Investors should readcarefully the following factors as well as the cautionary statements referred to in "Forward-Looking Statements" herein. If any of the risks and uncertaintiesdescribed below or elsewhere in this Annual Report on Form 10-K actually occur, the Company's business, financial condition or results of operations couldbe 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 isdue to a variety of factors that are beyond QEP's control, including:31•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 otherfactors 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 ofOPEC 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 MiddleEast, 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 andgas 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 mayhave 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 andraise 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 pricesmay 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 produceeconomically. 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 hasimpairments. QEP is required to perform impairment tests on its assets periodically and whenever events or changes in circumstances warrant a review of itsassets. 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 berecoverable, 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, onits unproved properties. QEP also recorded an impairment of $6.5 million on its underground gas storage facility during the year ended December 31, 2017and 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 toPart I, Item 8, Note 1 – Summary of Significant Accounting Policies, of this Annual Report on Form 10-K for additional information.32If forward oil prices decline from December 31, 2017 levels or we experience negative changes to the estimated reserve quantities, we have proved andunproved properties with a net book value of approximately $2.7 billion, as of December 31, 2017, at risk for impairment, primarily associated with ourWilliston 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-averagecost 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 aregenerally characterized by declining production rates that vary depending on reservoir characteristics. Because oil and gas production volumes fromunconventional 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 oracquire 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 reserveestimates or underlying assumptions may negatively affect the quantities and present value of QEP's reserves. QEP's proved oil and gas reserve estimates areprepared annually by independent reservoir engineering consultants. Oil and gas reserve estimates are subject to numerous uncertainties inherent inestimating quantities of proved reserves, projecting future rates of production and timing of development expenditures. The accuracy of these estimatesdepends on the quality of available data and on engineering and geological interpretation and judgment. Reserve estimates are imprecise and will change asadditional information becomes available. Estimates of economically recoverable reserves and future net cash flows prepared by different engineers or by thesame engineers at different times may vary significantly. Results of subsequent drilling, testing and production may cause either upward or downwardrevisions of previous estimates. In addition, the estimation process involves economic assumptions relating to commodity prices, operating costs, severanceand other taxes, capital expenditures and remediation costs. Actual results most likely will vary from the estimates. Any significant variance from theseassumptions could affect the recoverable quantities of reserves attributable to any particular property, the classifications of reserves, the estimated future netcash 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 thisAnnual 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, theestimated 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 onthe 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 costestimates do not include any carbon pollution costs associated with climate change damages. Actual future production, prices and costs may differ materiallyfrom those used in the current estimate, and future determinations of the Standardized Measure of Discounted Future Net Cash Flows using similarlydetermined prices and costs may be significantly different from the current estimate. Therefore, reserve quantities may change when actual prices increase ordecrease. In addition, the 10% discount factor QEP uses when calculating discounted future net cash flows in accordance with SEC disclosure rules, may notbe 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 gasindustry in general.In addition, realization or recognition of proved undeveloped reserves will depend on QEP's development schedule and plans. A change in futuredevelopment 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 theresults of our drilling operations. Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assistgeoscientists 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-drillingexpenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not besuccessful or economical.33Shortages of qualified personnel and/or oilfield equipment and services could impact results of operations. The oil and gas industry has long suffered askills 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 threeyears 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 andexperienced personnel to drill wells and conduct field operations, in addition to geologists, geophysicists, engineers, landmen and other professionals in theoil and gas industry, will create challenges for QEP and its competitors and may cause periodic and problematic personnel shortages. In periods of highcommodity prices, there have also been regional shortages of drilling rigs and other equipment. Any cost increases could impact profit margin, cash flow andoperating 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 operationalrisks 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 intothe 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 orequipment, regulatory compliance investigations, fines or curtailment of operations, or attorneys' fees and other expenses incurred in the prosecution ordefense of litigation. As a working interest owner in wells operated by other companies, QEP may also be exposed to the risks enumerated above fromoperations 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 certainlosses suffered by QEP as the operator and certain third parties resulting from a well blowout or fire or other uncontrolled flow of hydrocarbons, regardless offault. 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 thecleanup of any pollution or contamination resulting from a blowout in addition to claims for personal injury or death suffered by QEP's employees andcertain others. QEP's drilling contracts and oilfield service agreements, however, often provide that the contractor will indemnify QEP for claims related toinjury 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 forcertain other risks, such political risk, lost reserves, business interruption, cyber risk, earthquakes, war and terrorism. Although QEP believes the coverage andamounts of insurance that it carries are consistent with industry practice, QEP does not have insurance protection against all risks that it faces because QEPchooses 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 lossesmay exceed coverage limits. QEP could sustain significant losses and substantial liability for uninsured risks. The occurrence of a significant event againstwhich QEP is not fully insured could have a material adverse effect on its financial condition, results of operations and cash flows.34Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in theirapplication. Our operations involve utilizing some of the latest drilling and completion techniques. Risks that we face while drilling horizontal wellsinclude, 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 itsWilliston Basin properties during 2017. Refracturing an existing well is technically more challenging than fracturing a new well and may result in the loss ofthe existing producing well.The use of new horizontal drilling and completion techniques that simultaneously develop multiple producing horizons can add complexity to fielddevelopment. 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 ofcapital constraints, lease expirations, limited access to gathering systems, limited takeaway capacity and/or declines in crude oil and natural gas prices, thereturn 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 incurmaterial 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 withenvironmental, safety and other regulations, or the amount or timing of capital expenditures that QEP is required to fund with respect to them. The failure ofan 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 waysthat 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 completethese projects and QEP's limited ability to influence or control the operation and future development of these properties could materially adversely affect therealization 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 wherepractical. For example, in the Permian Basin, QEP utilizes "tank-style” development, in which we drill and complete all wells in a given "tank" before anyindividual 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 productionuntil 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 maybe temporarily shut-in during the drilling and completion process. As a result, multi-well pad drilling delays the completion of wells and the commencementof production, which may cause volatility in QEP's operating results from period to period. Existing wells that offset new wells being completed by QEP oroffset 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 causevolatility in QEP's operating results from period to period. In addition, delays in completion of wells may impact planned conversion of PUD reserves toproved developed.35Lack of availability of refining, gas processing, storage, gathering or transportation capacity will likely impact results of operations. The lack ofavailability of satisfactory oil, gas and NGL gathering and transportation, including trucks, railways and pipelines, gas processing, storage or refiningcapacity 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 insubstantial part on the availability and capacity of gathering, transportation, gas processing facilities, storage or refineries owned and operated by thirdparties. Although QEP has some contractual control over the transportation of its production through firm transportation arrangements, third-party systemsmay be temporarily unavailable due to market conditions, mechanical failures, accidents or other reasons. If gathering, transportation, gas processing orstorage 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 productionshut-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 chargesfor gathering and processing services, firm transportation charges on interstate pipelines as well as shut-in royalties to certain mineral interest owners in orderto maintain its leases; or depending on the specific lease provisions, some leases could terminate. In addition, rail accidents involving crude oil carriers haveresulted in new regulations, and may result in additional regulations, on transportation of oil by railway. QEP might be required to install or contract foradditional treating or processing equipment, which could increase costs. Federal and state regulation of oil and gas production and transportation, tax andenergy policies, changes in supply and demand, transportation pressures, damage to or destruction of transportation facilities and general economicconditions 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 onthe acreage or on units containing the acreage or the leases are otherwise renewed or extended. Leases on oil and gas properties typically have a primaryterm of three to five years after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities isestablished 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'sdrilling plans are subject to change based upon various factors, including drilling results, oil and gas prices, the availability and cost of capital, drilling andproduction 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 withinfive years. SEC rules require that, subject to limited exceptions, proved undeveloped (PUD) reserves may only be classified as proved reserves if they are fromlocations scheduled to be drilled within five years after the date of booking. Recovery of PUD reserves requires the expenditure of significant capital andsuccessful 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-yeartime 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 2017forecasted capital expenditure plans, respectively, and would not be drilled and completed within five years of the initial date of booking of the reserves. AtDecember 31, 2017, approximately 63% of QEP's estimated proved reserves were PUD reserves. These reserve estimates reflect the Company's plans to makesignificant capital expenditures to convert its PUDs into proved developed reserves, requiring an estimated $4.3 billion during the five years endingDecember 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 theoccurrence 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 itspotential well locations. QEP has identified and scheduled well locations to build its multi-year development plan for its existing leaseholds. These welllocations 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 productioncosts, availability of drilling services and equipment, drilling results, potential interference between infill and existing wells, lease expirations, gatheringsystem 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 fromthese or any other potential well locations. In addition, any drilling activities QEP is able to conduct on these potential locations may not be successful orresult 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.36Renegotiation of gathering, processing and transportation agreements may result in higher costs and/or delays in selling production. Due to marketconditions over the past few years, many midstream companies have attempted to renegotiate their gathering, processing and transportation agreements withtheir 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 oralter 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 andfurther delays.QEP is required to pay fees to some of its midstream service providers based on minimum volumes regardless of actual volume throughput. QEP hascontracts with some third-party service providers for gathering, processing and transportation services with minimum volume delivery commitments. As ofDecember 31, 2017, QEP's aggregate long-term contractual obligation under these agreements was $392.9 million. QEP is obligated to pay fees on minimumvolumes to service providers regardless of actual volume throughput. These fees could be significant and have a material adverse effect on QEP's results ofoperations.QEP is dependent on its revolving credit facility and continued access to capital markets to successfully execute its operating strategies. If QEP is unable tomake capital expenditures or acquisitions because it is unable to obtain capital or financing on satisfactory terms, QEP may experience a decline in its oil andgas production rates and reserves. QEP is partially dependent on external capital sources to provide financing for certain projects. The availability and cost ofthese 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 thefuture. Over the last few years, conditions in the global capital markets have been volatile, making terms for certain types of financing difficult to predict, andin 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, operatingdifficulties, declines in production or for any other reason, QEP may have limited ability to obtain the capital necessary to sustain its operations at currentlevels. 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 itsrevolving credit facility, provided by a group of financial institutions, to meet short-term funding needs. Borrowings under its revolving credit facility incurfloating 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 interestrates 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 toobtain additional financing could result in a curtailment of its operations relating to exploration and development of its prospects, which in turn could leadto 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 atDecember 31, 2017. QEP also has various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations forservices, products and properties. QEP's financial commitments could have important consequences to its business, including, but not limited to, limitingQEP's ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, or to otherwise realize thevalue 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 tocomply with any restrictive terms of its debt. QEP may be at a competitive disadvantage as compared to similar companies that have less debt. Higher levelsof debt may make QEP more vulnerable to general adverse economic and industry conditions. Additionally, the agreement governing QEP's revolving creditfacility and the indentures covering QEP's senior notes contain a number of covenants that impose constraints on the Company, including restrictions onQEP's ability to dispose of assets, make certain investments, incur liens and additional debt, and engage in transactions with affiliates. If commodity pricesdecline and QEP reduces its level of capital spending and production declines or QEP incurs additional impairment expense or the value of the Company'sproved reserves declines, the Company may not be able to incur additional indebtedness and may not be in compliance with the financial covenants in itscredit agreement in the future. Refer to Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations in Part II of thisAnnual 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 financialcovenants 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+ byStandard & 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 ofQEP'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 toprovide financial assurance of its performance under certain contractual arrangements and derivative agreements. In addition, a downgrade of QEP's creditratings 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 thatQEP may incur.37Failure to fund continued capital expenditures could adversely affect QEP's properties. QEP's exploration, development and acquisition activities requirecapital expenditures to achieve production and cash flows. Historically, QEP has funded its capital expenditures through a combination of cash flows fromoperations, its revolving credit facility, debt issuances, equity offerings and sales of assets. Future cash flows from operations are subject to a number ofvariables, such as the level of production from existing wells, prices of oil, gas and NGL, and QEP's success in finding, developing and producing newreserves.QEP's use of derivative instruments to manage exposure to uncertain prices could result in financial losses or reduce its income. QEP uses commodity pricederivative arrangements to reduce exposure to the volatility of oil, gas and NGL prices, and to protect cash flow and returns on capital from downwardcommodity price movements. QEP's derivative transactions are limited in duration, usually for periods of one to three years. QEP's derivatives portfolio maybe inadequate to protect it from prolonged declines in the price of oil or natural gas. To the extent the Company enters into commodity derivativetransactions, it may forgo some or all of the benefits of commodity price increases. Furthermore, QEP's use of derivative instruments through which it attemptsto 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 occurredduring the applicable period. QEP has incurred significant unrealized gains and losses in prior periods and may continue to incur these types of gains andlosses 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 tooutstanding accounts receivable from purchasers of its production and joint working interest owners. This counterparty credit risk is heightened during timesof economic uncertainty, tight credit markets and low commodity prices. Because QEP is the operator of a majority of its production and major developmentprojects, 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 jointventure costs. Counterparty liquidity problems could result in a delay or collection issues in QEP receiving proceeds from commodity sales or reimbursementof joint venture costs. Credit enhancements, such as parental guarantees, letters of credit or prepayments, have been obtained from some but not allcounterparties. Nonperformance by a trade creditor or joint venture partner could result in financial losses. In addition, QEP's commodity derivativetransactions expose it to risk of financial loss if the counterparty fails to perform under a contract. During periods of falling commodity prices, QEP'scommodity 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 changein 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 creditworthinessor 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 usederivative instruments to reduce the effect of commodity price volatility and other risks associated with its business. The Dodd-Frank Act, which was signedinto law in July 2010, contains significant derivatives regulation, including, among other items, a requirement that certain transactions be cleared onexchanges as well as collateral or "margin" requirements for certain uncleared swaps. The Dodd-Frank Act provides for an exception from these clearingrequirements for commercial end-users, such as QEP. The Dodd-Frank Act and the rules promulgated thereunder could significantly increase the cost ofderivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability ofderivatives to protect against risks QEP encounters, reduce QEP's ability to monetize or restructure QEP's existing derivative contracts, increase theadministrative burden and regulatory risk associated with entering into certain derivative contracts, and increase QEP's exposure to less creditworthycounterparties. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed tospeculative trading in derivatives and commodity contracts related to oil and gas. QEP revenues could therefore be adversely affected if a consequence of theDodd-Frank Act and its regulations is to lower commodity prices. Any of these consequences could affect the pricing of derivatives and make it more difficultfor 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 onQEP's business remains uncertain.38QEP faces various risks associated with the trend toward increased opposition to oil and gas exploration and development activities. Opposition to oil andgas drilling and development activity has been growing globally and is particularly pronounced in the U.S. Companies in the oil and gas industry, such asQEP, 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 asthe development of oil or gas shale plays. For example, ENGOs and other environmental activists continue to advocate for increased regulations on shaledrilling 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 thefollowing:•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 hydraulicfracturing 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 requirementsthat 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 highlycompetitive 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 gasproperties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than QEP's financial or humanresources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than QEP is able tooffer. This highly competitive environment could have an adverse impact on QEP's ability to execute its strategy, QEP's financial condition and its results ofoperations.39QEP may be unable to make acquisitions, successfully integrate acquired businesses and/or assets, or adjust to the effects of divestitures, causing adisruption 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 ifQEP does identify additional acquisition opportunities, it may not be able to complete the acquisitions due to capital constraints. Any acquisition of abusiness 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 regardingfuture 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 oroperations of the acquired properties.Organizational modifications due to acquisitions, divestitures or other strategic changes can alter the risk and control environments; disrupt ongoingbusiness; distract management and employees; increase expenses; result in additional liabilities, investigations and litigation; harm QEP's strategy; andadversely affect results of operations. Even if these challenges can be dealt with successfully, the anticipated benefits of any acquisition, divestiture or otherstrategic 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 orcombination transactions. QEP's credit agreement also limits QEP's ability to incur certain indebtedness, which could limit QEP's ability to engage inacquisitions.QEP may be unable to divest of assets on financially attractive terms, resulting in reduced cash proceeds. QEP is continuously evaluating the sale of certainupstream 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 todispose of assets on terms acceptable to QEP. Such factors include, but are not limited to: current and forecasted commodity prices; current laws, regulationsand 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; andother 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 assetsthan 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 financialcondition. Like many oil and gas companies, the Company is involved in various legal proceedings, including threatened claims, such as title, royalty, andcontractual disputes. The cost to settle legal proceedings (asserted or unasserted) or satisfy any resulting judgment against the Company in such proceedingscould result in a substantial liability or the loss of interests, which could materially and adversely impact the Company's cash flows, operating results andfinancial 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. Inaddition, legal proceedings distract management and other personnel from their primary responsibilities.40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 allpossible errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that theobjectives 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 thebenefit of controls are evaluated relative to their costs. Because of the inherent limitations in all control systems, no evaluation of QEP's controls can provideabsolute 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 inpart 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 futureconditions. Over time, a control may become inadequate because of changes in conditions, or the degree of compliance with its policies or procedures maydeteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection. Violations ofany laws or regulations caused by either failure of our internal controls related to regulatory compliance or failure of our employees to comply with ourinternal policies could result in substantial civil or criminal fines. In addition, legal enforcement may be impacted by significant incentives forwhistleblowers.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 ofproved 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 theCompany's operations increases its cost of doing business and, consequently, affects its profitability. In addition to the costs of compliance, substantial costsmay be incurred to take corrective actions at both owned and previously owned facilities. Accidental spills and leaks requiring cleanup may occur in theordinary course of QEP's business. As standards change, the Company may incur significant costs in cases where past operations followed practices that wereconsidered acceptable at the time, but now require remedial work to meet current standards. Failure to comply with these laws and regulations may result infines, 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 and2014. Subpart OOOO imposes air quality controls and requirements upon QEP's operations. Additionally, in June 2016, the EPA finalized closely relatedrules in new Subpart OOOOa to achieve additional methane and volatile organic compound reductions from certain activities in the oil and gas industry. Thenew rules include, among others, new requirements for finding and repairing leaks at new well sites and "reduced emission completion" requirements forhydraulically fractured oil and gas wells. The future status of Subpart OOOOa remains uncertain given ongoing litigation and administrative regulatoryactions. EPA has proposed a two-year stay of the effective dates of several requirements of Subpart OOOOa, including fugitive emission requirements, wellsite 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 thatare more stringent than existing requirements under federal regulations.41Regulatory requirements to reduce gas flaring and to further restrict emissions could have an adverse effect on our operations. Wells in the WillistonBasin of North Dakota and the Permian Basin of Texas, where QEP has significant operations, produce natural gas as well as crude oil. Constraints in thirdparty gas gathering and processing systems in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. InJune 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 theWilliston Basin. The Commission requires operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it willbe 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. Itis 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 andFlaring Rule). The rule took effect in January 2017. Some provisions of the rule required compliance in January 2017, including the royalty provisions, whileother provisions including those related to further controls on the venting and flaring of natural gas, did not require compliance until January 2018. The2016 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 BLMpublished a rule to delay the January 2018 compliance deadlines and suspend the obligation to comply with certain provisions that had required compliancein January 2017, until January 2019 (2017 Delay Rule). Certain states and ENGOs filed litigation in the U.S. District Court for the Northern District ofCalifornia challenging the 2017 Delay Rule, and the court preliminarily enjoined the 2017 Delay Rule on February 22, 2018, requiring operators toimmediately comply with the 2016 Venting and Flaring Rule. These state and federal gas capture requirements, and any similar future obligations in NorthDakota or our other locations, increase our operational costs and may restrict our production, which could materially and adversely affect our financialcondition, 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 IndustrialCommission requires that crude oil produced in the Bakken Petroleum System be conditioned to remove lighter, volatile hydrocarbons and improve themarketability and safe transportation of the crude oil. The U.S. Department of Transportation rule regarding the safe transportation of flammable liquids byrail imposes certain requirements on "offerors" of crude oil, including sampling, testing, and certification requirements. These conditioning requirements, andany similar future obligations imposed at the state or federal level, may increase our operational costs or restrict our production, which could materially andadversely 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 wherewe operate. Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activitiesdesigned to protect various species and wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition fordrilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraintsand the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed toprotect threatened and endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. Thedesignation of previously unprotected species as threatened or endangered in areas where we operate could cause us to incur increased costs arising fromspecies protection measures or could result in limitations on our exploration and production activities that could have a material adverse effect on our abilityto 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 theLesser Prairie-Chicken as a threatened or endangered species. The Lesser Prairie-Chicken is a grouse species native to Texas, including parts of the PermianBasin 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 ofmaking 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 tribalenvironmental 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 tribalregulatory agencies frequently impose conditions on the Company's activities under these laws. These restrictions have become more stringent over time andcan limit or prevent exploration and production on significant portions of the Company's leasehold. These laws also allow certain ENGOs to oppose drillingon some of QEP's federal and state leases. These organizations sometimes sue federal and state regulatory agencies and/or the Company under these laws foralleged procedural violations in an attempt to stop, limit or delay oil and gas development on public and other lands.42QEP may not be able to obtain the permits and approvals necessary to continue and expand its operations. Regulatory authorities exercise considerablediscretion in the timing and scope of permit issuance. It may be costly and time consuming to comply with requirements imposed by these authorities, andcompliance may result in delays in the commencement or continuation of the Company's exploration and production. Further, the public may comment onand otherwise seek to influence the permitting process, including through intervention in the courts. Accordingly, necessary permits may not be issued, or ifissued, 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. Inaddition, the BIA implemented final regulations in March 2016, which significantly altered the procedure for obtaining rights-of-way on tribal lands. Thesenew 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 welldesign and operation. The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the SDWAand issued guidance related to this asserted regulatory authority. The EPA may consider seeking to further regulate hydraulic fracturing fluids and/or thecomponents of those fluids. At the state level, some states have adopted and other states have considered adopting regulations and moratoria that couldrestrict or prohibit hydraulic fracturing in certain circumstances. If new or more stringent federal, state or local regulations, restrictions or moratoria areadopted in areas where QEP operates, QEP could incur potentially significant added costs to comply with such requirements, experience delays orcurtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling or stimulating wells in someareas.In December 2016, the EPA released its final report on the potential impacts to drinking water resources from hydraulic fracturing. The study concluded thathydraulic fracturing activities can impact drinking water resources under some circumstances. Many other recent studies and reports have examined thepotential impacts of hydraulic fracturing on the public and the environment. These or future studies could result in additional regulations, which could leadto 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 forits 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 applicableenvironmental rules. The hydraulic fracture stimulation process on which QEP depends to produce commercial quantities of oil and gas requires the use anddisposal of significant quantities of water. The availability of disposal wells with sufficient capacity to receive all of the water produced from QEP's wellsmay 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 ashydraulic 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 surfacewater or groundwater necessary for hydraulic fracturing of wells may increase QEP's operating costs or may cause QEP to delay, curtail or discontinue itsexploration 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 abilityto dispose of produced water gathered from such activities, which could have a material adverse effect on QEP's business. State and federal regulatoryagencies have focused on a possible connection between the disposal of wastewater in underground injection wells and the increased occurrence of seismicactivity in certain areas, and regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and inducedseismicity. For example, in 2015, the United States Geological Survey identified eight states, including Texas, with areas of increased rates of seismic activitythat may be attributable to fluid injection or oil and natural gas extraction activities. In addition, a number of lawsuits have been filed, alleging that disposalwell operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to theseconcerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wellsor otherwise to assess any relationship between seismicity and the use of such wells. For example, in October 2014, the Railroad Commission of Texaspublished a new rule governing permitting or re-permitting of disposal wells that requires, among other things, the submission of information on seismicevents occurring within a specified radius of the disposal well location as well as logs, geologic cross sections and structure maps relating to the disposal areain 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 dataindicates the well is likely or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permitapplication or existing operating permit for that well.43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 authoritiesoverseeing 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 operatingcertain facilities, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. Theadoption 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 usehydraulic fracturing or dispose of produced water gathered from its drilling and production activities by limiting volumes, injection pressures or rates, orproducing or disposal well locations, or requiring QEP to shut down disposal wells, could have a material adverse effect on QEP's business, financialcondition 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 andnatural gas that we produce. Climate change, the costs that may be associated with its effects and the regulation of greenhouse gas (GHG) emissions have thepotential to affect our business in many ways, including increasing the costs to provide our products, reducing the demand for and consumption of ourproducts (due to changes in both costs and weather patterns) and negatively impacting the economic health of the regions in which we operate, all of whichcan create financial risks. In addition, if restrictions on GHG emissions significantly increase our costs to produce oil and gas, or significantly decreasedemand 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 afinancial risk, this could negatively impact our cost of and access to capital. In addition, legislative and regulatory responses related to GHG emissions andclimate change may result in increased operating costs, delays in obtaining air pollution and other necessary permits for new or modified facilities andreduced demand for the oil, gas and NGL that QEP produces. Federal and state courts and administrative agencies are considering the scope and scale ofclimate change regulation under various laws pertaining to the environment, energy use and energy resource development. Federal, state and localgovernments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, or banning the use of gasoline ordiesel powered vehicles, which may reduce demand for oil and natural gas. Further, state and local governments may pursue litigation against producers fordamages allegedly resulting from climate change, similar to the lawsuits filed by the cities of San Francisco and Oakland, California, in September 2017, andthe lawsuit filed by the City of New York in January 2018 against Chevron Corp., ConocoPhillips, Co., ExxonMobil Corp., Royal Dutch Shell Plc and BPp.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 andregulation.Congress has previously considered but not adopted proposed legislation aimed at reducing GHG emissions. The EPA has adopted final regulations underthe Clean Air Act for the measurement and reporting of GHG emitted from certain large facilities and, as discussed above, has adopted additional regulationsat 40 C.F.R Part 60, Subparts OOOO and OOOOa, to include additional requirements to reduce methane and volatile organic compound emissions from oiland natural gas facilities. The status of Subpart OOOOa is uncertain given the ongoing litigation, administrative reconsideration and proposed action to stayportions of those rules. Additionally, in June 2014, the United States Supreme Court upheld a portion of EPA's GHG stationary source permitting program inUtility 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, civiland/or criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations to whichQEP's operations are subject.44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 amaximum limit of two degrees Celsius and a target limit of 1.5 degrees Celsius greater than pre-industrial levels. In June 2017, President Trump announcedthat 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 ParisAgreement's legal structure and language. The current state of development of ongoing international climate initiatives and any related domestic actionsmake 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 futureinternational treaties or domestic regulations. Following the initiation of the U.S. withdrawal from the Paris Agreement, state and local regulation efforts areexpected to increase. In several of the states in which QEP operates the regulatory authorities are considering various GHG registration and reductionprograms, including methane leak detection monitoring and repair requirements specific to oil and gas facilities. For example, in January 2018, UDEQadopted additional rules that impose leak detection and repair requirements at certain oil and gas facilities in Utah. In addition, the failure of the federalgovernment to address climate change concerns, including, for example, a protracted delay by President Trump's administration in determining its owncarbon-cost estimate (i.e., the estimate of how much carbon pollution costs society via climate damages) after rejecting the $40 per ton of carbon dioxideequivalent 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 asan 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 greaterdegree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events (suchas increased frequency, duration, and severity) and the long period of time over which any changes would take place make any estimations of future financialrisk 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 maymake strategic proposals, suggestions or requested changes concerning our operations, strategy, management, assets or other matters. Responding to actionsby activist shareholders could be costly and time-consuming, disrupting our operations and diverting the attention of our management and employees. Suchactivities could interfere with our ability to execute our strategic plan or realize long-term value from our assets. The perceived uncertainties as to our futuredirection 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 fromretiring personnel, QEP's operations may be negatively impacted. QEP's performance largely depends on the talents and efforts of highly skilledindividuals. QEP's future success depends on its continuing ability to identify, hire, develop, motivate, and retain highly skilled personnel for all areas of itsorganization. Competition in the oil and gas industry for qualified employees is intense. QEP's continued ability to compete effectively depends on itsability to attract new employees and to retain and motivate its existing employees. QEP does not have employment agreements with or maintain key-maninsurance 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'sfinancial 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 notbe able to replace them with employees of comparable knowledge and experience. QEP's efforts at knowledge transfer could be inadequate. If knowledgetransfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could becomeunavailable 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 bychanges in global economic conditions; availability and economic viability of oil and gas properties for sale or exploration; rate of inflation and interestrates; 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 184participants who are retired or were terminated and vested. Effective January 1, 2016, the Pension Plan was frozen, such that employees do not earn additionaldefined benefits for future services. QEP also sponsors an unfunded, nonqualified Supplemental Executive Retirement Plan (the SERP). Over time, periods ofdeclines 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, 2017and 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'spension plans may require that the Company make large contributions to such plans. QEP made cash contributions of $6.0 million and $7.2 million duringthe years ended December 31, 2017 and 2016, respectively, to the Pension Plan and SERP and expects to make contributions of approximately $4.7 millionto these pension plans in 2018. QEP cannot, however, predict whether changing economic conditions, the future performance of assets in the plans or otherfactors 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/orfinancial 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 andgathering systems; conduct reservoir modeling and reserves estimation; and process and record financial and operating data. Pipelines, refineries, powerstations 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 mightbe specific targets of cyber security threats. QEP's technologies, systems, networks, and those of its vendors, suppliers and other business partners maybecome the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss ordestruction of proprietary and other information, or other disruption of its business operations. In addition, certain cyber incidents, such as surveillance, mayremain undetected for an extended period. QEP does not maintain specialized insurance for possible losses resulting from a cyberattack on its assets that mayshut 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 anyinformation 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 notsuffer such losses in the future. In addition, as cybersecurity threats continue to evolve, QEP may expend additional resources to continue to modify orenhance 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 issuepreferred 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 acquireQEP. 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 ofshareholders; 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'soutstanding common stock. These provisions may deter hostile takeover attempts that could result in an acquisition of QEP that could have been financiallybeneficial 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 fromissuing 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 orjust its common stock. QEP may also issue securities convertible into, exchangeable for or that represent the right to receive its common stock. Lastly, QEPissues 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 priceof 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 COMMENTSNone.47ITEM 3. LEGAL PROCEEDINGSThe 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 andthe proceedings involve potential monetary sanctions that the Company reasonably believes could exceed $100,000. The matters below are disclosedpursuant 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. Theinformation 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 thetank batteries to date, QEP anticipates that resolution of this matter will likely result in monetary penalties and require QEP to incur additional capitalexpenditures 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 theLouisiana Department of Environmental Quality (LDEQ) regarding the assumption of ownership and operatorship of a single facility in Louisiana prior totransferring the facility's air quality permit. In 2011, QEP completed an internal audit, which identified 424 facilities in Louisiana for which QEP both failedto submit a complete permit application and to receive approval from the department prior to construction, modification, or operation. QEP has corrected anddisclosed all known instances of non-compliance to the LDEQ and is working with the department to resolve the NOPP. The LDEQ has assumed leadresponsibility 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. Mabeeand 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 DistrictCourt of Martin County, Texas, asserting that the Company (1) trespassed on the surface of their land by continuing surface operations following the allegedtermination of certain surface use agreements and (2) breached various lease agreements by failing to correctly pay royalties and by allegedly using leaseproperty 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 propertiesare 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 legalproceedings.ITEM 4. MINE SAFETY DISCLOSURESNot applicable.48PART IIITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITYSECURITIESQEP'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. InFebruary 2016, in response to lower commodity prices, the Company's Board of Directors indefinitely suspended the payment of quarterly dividends. Thefuture 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 ofoperations, financial condition, contractual restrictions, cash requirements, future prospects and other factors deemed relevant by the Company's Board ofDirectors.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 pershare 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 GraphThe following stock performance information is not deemed to be "soliciting material" or to be "filed" with the SEC or subject to Regulation 14A or 14Cunder 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 beincorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent QEP specificallyincorporates 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 CorporationParsley Energy, Inc.Carrizo Oil & Gas, Inc.PDC Energy, Inc.Cimarex Energy CompanyRange Resources CorporationDiamondback Energy, Inc.RSP Permian, Inc.Energen CorporationSM Energy CompanyEP Energy CorporationSouthwestern Energy CompanyLaredo Petroleum, Inc.Whiting Petroleum CorporationNewfield Exploration CompanyWPX 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 CompanyPDC Energy, Inc.Diamondback Energy, Inc.Range Resources CorporationEnergen CorporationRSP Permian, Inc.EP Energy CorporationSM Energy CompanyLaredo Petroleum, Inc.Southwestern Energy CompanyNewfield Exploration CompanyWhiting Petroleum CorporationOasis 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 withinthe 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 2017QEP Resources, Inc.$100.00 $101.53 $67.16 $44.71 $61.43 $31.93S&P 500 Index – Total Returns$100.00 $132.39 $150.51 $152.59 $170.84 $208.14New Peer Group$100.00 $141.62 $99.12 $62.86 $96.97 $77.67Old Peer Group$100.00 $143.99 $102.44 $64.39 $97.39 $82.5050Recent Sales of Unregistered Securities; Purchases of Equity Securities by QEP and Affiliated PurchasersThe following repurchases of QEP shares were made by QEP in association with vested restricted stock awards withheld for taxes.Period Total sharespurchased (1) Weighted-averageprice paid pershare Total sharespurchased as part ofpublicly announcedplans or programs Maximum value that mayyet be purchased under theplans 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 thesettlement 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. Thetiming and amount of any QEP share repurchases will be subject to available liquidity, market conditions and proceeds from the asset sales. The repurchaseplan does not obligate QEP to acquire any specific number of shares and may be discontinued at any time.51ITEM 6. SELECTED FINANCIAL DATASelected 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). Inaddition, 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 ofsubstantially 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 forfurther 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) 2013Results of Operations (in millions, except per share amounts)Revenues(5) $1,622.9 $1,377.1 $2,018.6 $3,293.2 $2,685.1Operating income (loss)(6) 101.5 (1,600.7) (364.5) (840.3) 211.9Income (loss) from continuing operations 269.3 (1,245.0) (149.4) (409.5) 52.1Net income from discontinued operations, net of income tax(7) — — — 1,193.9 107.3Net income (loss)(8) 269.3 (1,245.0) (149.4) 784.4 159.4Earnings (loss) per common share(8) Basic from continuing operations $1.12 $(5.62) $(0.85) $(2.28) $0.29Basic from discontinued operations(7) — — — 6.64 0.60Basic total $1.12 $(5.62) $(0.85) $4.36 $0.89Diluted from continuing operations(8) $1.12 $(5.62) $(0.85) $(2.28) $0.29Diluted from discontinued operations(7) — — — 6.64 0.60Diluted total $1.12 $(5.62) $(0.85) $4.36 $0.89Weighted-average common shares outstanding Used in basic calculation 240.6 221.7 176.6 179.8 179.2Used in diluted calculation 240.6 221.7 176.6 179.8 179.5Dividends per common share $— $— $0.08 $0.08 $0.08Financial Position Total Assets at December 31, $7,394.8 $7,245.4 $8,398.2 $9,256.4 $9,380.4Capitalization at December 31, Long-term debt 2,160.8 2,020.9 2,191.5 2,187.7 2,969.0Total equity 3,797.9 3,502.7 3,947.9 4,075.3 3,876.8Total Capitalization $5,958.7 $5,523.6 $6,139.4 $6,263.0 $6,845.8Cash Flow From Operations Net cash provided by (used in) operating activities $598.4 $663.7 $481.3 $1,542.5 $1,191.7Capital 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) 279.8Non-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. Referto 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 PermianBasin Acquisition.52(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 October2016. 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 2016Permian 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 occurredin 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 Marketingand QEP Energy. In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing andtransportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and Haynesville Gathering. Asa result, QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had in priorperiods.(6) In the first quarter of 2017, QEP early adopted ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation ofnet periodic pension cost and net periodic postretirement benefit cost, which is effective retrospectively. As a result, the Company has recastoperating income and Adjusted EBITDA for all prior periods shown. The Company recognizes service costs related to SERP and Medical Planbenefits within "General and administrative" expense on the Consolidated Statements of Operations and all other expenses related to the PensionPlan, SERP and Medical Plan are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations. Refer toNote 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 resultsof Haynesville Gathering) have been reflected as discontinued operations and results for the years ended December 31, 2014 and 2013, have beenreclassified.(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 toreflect 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 fromasset sales, impairment, loss from early extinguishment of debt and certain other items. See Part II, Item 7 – Management's Discussion and Analysisof Financial Condition and Results of Operations, in this Annual Report on Form 10-K for additional disclosures related to Adjusted EBITDA.53The following table reconciles QEP's Net Income (Loss) (a GAAP measure) to Adjusted EBITDA. This non-GAAP measure should be considered by the readerin 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 $159.4Net income from discontinued operations, net of tax— — — (1,193.9) (107.3)Net income (loss) from continuing operations269.3 (1,245.0) (149.4) (409.5) 52.1Interest expense137.8 143.2 145.6 169.1 165.1Interest 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) 60.1Depreciation, depletion and amortization754.5 871.1 881.1 994.7 963.8Unrealized (gains) losses on derivative contracts(40.0) 367.0 183.7 (374.4) 88.7Exploration expenses22.0 1.7 2.7 9.9 11.9Net (gain) loss from asset sales(213.5) (5.0) (4.6) 148.6 (103.5)Impairment78.9 1,194.3 55.6 1,143.2 93.0Loss from early extinguishment of debt32.7 — — 2.0 —Other(1)(2)8.2 32.7 — — —Adjusted EBITDA from continuing operations736.1 628.1 1,031.2 1,445.3 1,324.9Adjusted EBITDA from discontinued operations— — — 144.4 220.7Adjusted 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 ofnet periodic pension cost and net periodic postretirement benefit cost, which is effective retrospectively. As a result, the Company recast "Interestand other (income) expense" and "Other" for all prior periods shown. The Company recognizes service costs related to SERP and Medical Planbenefits within "General and administrative" expense on the Consolidated Statements of Operations and all other expenses related to the PensionPlan, 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 theseamounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore hasexcluded these amounts from the calculation of Adjusted EBITDA.54ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSManagement's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide the reader of the financialstatements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that mayaffect the Company's operating results. MD&A should be read in conjunction with the Consolidated Financial Statements and related Notes included in Item8 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 thechanges in the results of operations between the years ended December 31, 2017 and 2016, and between the years ended December 31, 2016 and 2015.OVERVIEWQEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: theNorthern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the contextotherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporateheadquarters 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 NGLproduction. Since the beginning of 2012, the Company has made approximately $3.9 billion of acquisitions of oil-weighted properties, spent approximately60% 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 totalproduction compared to 14% in 2011. Additionally, oil and NGL revenue represented 68% of total field-level revenues during 2017 compared to 27% in2011. Approximately 56% of total proved reserves at year-end 2017 were oil and NGL. Consistent with its emphasis on oil-weighted properties, QEP nowreflects its production and reserve amounts in oil equivalent volumes rather than gas equivalent volumes. In February 2018, QEP's Board of Directors hasunanimously approved several strategic initiatives including plans to market its assets in the Williston Basin, the Uinta Basin and Haynesville/Cotton Valleyand focus its activities in the Permian Basin.Acquisitions and DivestituresWhile QEP believes its extensive inventory of identified drilling locations provides a solid base for growth in production and reserves, the Companycontinues to evaluate and acquire properties in its existing areas of operations to add additional acreage and facilitate the drilling of long lateral wells. QEPbelieves that its experience, expertise and presence in its core operating areas, combined with its financial strength, enhances its ability to pursue acquisitionopportunities. The Company continuously evaluates potential acquisition, divestiture and joint venture opportunities that align with its strategic objectives.AcquisitionsIn 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, subjectto 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 RevenueService 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 whoown additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions asthe original purchase. If all offers are accepted, QEP now expects that the aggregate purchase price will not exceed $50.0 million. In February 2018, QEPentered into agreements related to these offers for an aggregate purchase price of $36.1 million, subject to customary purchase price adjustments. Thetransactions 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 of2018. In addition to the 2017 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2017, which primarily included undevelopedleasehold acreage, producing wells and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million.55In October 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $591.0 million. The 2016Permian Basin Acquisition consisted of approximately 9,600 net acres in Martin County, Texas, which are primarily held by production from existingvertical wells. The 2016 Permian Basin Acquisition was funded with cash on hand, which included proceeds from an equity offering in June 2016. Inaddition to the 2016 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2016, primarily in the Permian and Williston basins, for anaggregate 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 purchaseprice of $98.3 million, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage.DivestituresIn 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) fromasset sales" on the Consolidated Statements of Operations. QEP also sold its Central Basin Platform assets (Central Basin Platform Divestiture) and receivednet 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 moreinformation. 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 HighlightsDuring 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 expensesassociated with the repayment and used the remainder for general corporate purposes.OutlookSince the commodity price downturn in late 2014, the Company has focused on operating costs, per well drilling costs and managing its liquidity whilecontinuing its transition from a natural gas weighted company to a more balanced portfolio. We believe our balance sheet and sufficient liquidity will allowus 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 propertyacquisitions), a decrease of approximately 12% from 2017 capital expenditures. We continuously evaluate our level of drilling and completion activity inlight 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.56Factors Affecting Results of OperationsSupply, Demand, Market Risk and their Impact on Oil and Gas PricesOil and gas prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weatherconditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. In recentyears, oil and gas prices have been affected by supply growth, particularly in U.S. oil and gas production, driven by advances in drilling and completiontechnologies, 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 ofoperations, planned drilling and completion activity and related capital expenditures, our proved undeveloped (PUD) reserves conversion rate, liquidity, rateof 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 lowof $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 alow 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 NGLcomponents, typically correlated to oil prices, have declined in concert with weakening oil prices. Concurrently, the lighter NGL components, ethane andpropane, have experienced declines as a result of growing North American oversupply. In addition to commodity price movements, QEP's composite NGLprices 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 gasstream, the average sales price of a NGL barrel decreases as the ethane price is generally lower than the prices of the remaining NGL components. Aspermitted in some of its processing agreements, QEP recovers ethane when gas processing economics support the recovery of ethane from the natural gasstream. When gas processing economics do not support ethane recovery, and processing agreements permit it to do so, QEP elects to reject ethane from theNGL stream. In instances where QEP can make an election, QEP rejected ethane during the year ended December 31, 2017, and assuming similar ethane andnatural gas prices, plans to reject ethane during 2018.Global Geopolitical and Macroeconomic FactorsQEP 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, andAfrica; 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 invarious global currencies; and other factors. A dramatic decline in regional or global economic conditions, a major recession or depression, regional politicalinstability, economic sanctions, war, or other factors beyond the control of QEP could have a significant impact on oil, gas and NGL supply, demand andprices and the Company's ability to continue its planned drilling programs and could materially impact the Company's financial position, results ofoperations 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 theglobal oil supply system, political and/or economic instability, fluctuations in currency values, and/or other factors could trigger additional volatility in oilprices.Due to continued global economic uncertainty and the corresponding volatility of commodity prices, QEP continues to focus on a sufficient liquidityposition to ensure financial flexibility. QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production andto partially protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter into commodity derivativecontracts 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 itsforecasted gas production covered with fixed-price swaps. The average swap prices for the derivative contracts could be significantly lower than the averageswap 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 pricesfor current and future production. See Item 7A – "Quantitative and Qualitative Disclosures about Market Risk – Commodity Price Risk Management", of PartII of this Annual Report on Form 10-K for further details concerning QEP's commodity derivatives transactions.57Potential for Future Asset ImpairmentsThe carrying values of the Company's properties are sensitive to declines in oil, gas and NGL prices as well as increases in various development andoperating 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 thatare 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 transportationinfrastructure 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 ourcapitalized costs to changes in the assumptions in our cash flow calculations is not practicable, given the numerous assumptions (e.g., future oil, gas and NGLprices; production and reserves; pace and timing of development plans; timing of capital expenditures; operating costs; drilling and development costs; andinflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offsetby favorable adjustments in other assumptions. For example, the impact of sustained reduced oil, gas and NGL prices on future undiscounted cash flowswould 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 theOther Northern area, underground gas storage facility and unproved properties in the Permian Basin. During the year ended December 31, 2016, impairmentswere $1,194.3 million primarily due to impairments of proved properties in Pinedale. During the year ended December 31, 2015, impairments were $55.6million 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 AnnualReport 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 unprovedproperty 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 forwardprice 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 DrillingTo reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well paddrilling 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 onthe 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 thecommencement 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. Inaddition, delays in completion of wells may impact planned conversion of PUD reserves to proved developed reserves.Uncertainties Related to ClaimsQEP is currently subject to claims that could adversely impact QEP's liquidity, operating results, capital expenditures and financial condition, including, butnot 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.58RESULTS OF OPERATIONSNet IncomeQEP 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 $1,245.0million, 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 anincrease of $257.5 million in realized and unrealized derivative gains. Net income during the year ended December 31, 2017, was also positively impactedby 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, wasprimarily 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 unrealizedlosses on derivative contracts and a 17% increase in general and administrative expense. These changes were partially offset by a 2% increase in oilequivalent production, a 19% decrease in production and property taxes and a 6% decrease in lease operating expense.Adjusted EBITDAManagement defines Adjusted EBITDA as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA), adjusted to excludechanges in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment, loss from early extinguishment of debt andcertain other items. Management uses Adjusted EBITDA to evaluate QEP's financial performance and trends, make operating decisions and allocateresources. 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 bedetermined or calculated differently than similarly titled measures of other companies in our industry, which would reduce the usefulness of this non-GAAPfinancial measure when comparing our performance to that of other companies.59Below is a reconciliation of net income (loss) (a GAAP measure) to Adjusted EBITDA. This non-GAAP measure should be considered by the reader inaddition 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 expense137.8 143.2 145.6Interest and other (income) expense(1)(1.6) (23.7) 10.1Income tax provision (benefit)(312.2) (708.2) (93.6)Depreciation, depletion and amortization754.5 871.1 881.1Unrealized (gains) losses on derivative contracts(40.0) 367.0 183.7Exploration expenses22.0 1.7 2.7Net (gain) loss from asset sales(213.5) (5.0) (4.6)Impairment78.9 1,194.3 55.6Loss from early extinguishment of debt32.7 — —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 ofnet periodic pension cost and net periodic postretirement benefit cost, which is effective retrospectively. As a result, the Company recast "Interestand other (income) expense" and "Other" for all prior periods shown. The Company recognizes service costs related to SERP and Medical Planbenefits within "General and administrative" expense on the Consolidated Statements of Operations and all other expenses related to the PensionPlan, 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 theseamounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore hasexcluded 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. Thesechanges were partially offset by a 5% decrease in oil equivalent production, a 31% increase in lease operating expense and a 21% increase in production andproperty 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 andproperty taxes and a 6% decrease in lease operating expense.60RevenueRevenue, Volume and Price Variance AnalysisThe following table shows volume and price related changes for each of QEP's production-related revenue categories for the year ended December 31, 2017compared to the years ended December 31, 2016 and 2015: Oil Gas NGL TotalProduction revenues(in millions)Year ended December 31, 2015$834.2 $468.5 $80.0 $1,382.7Changes associated with volumes(1)30.2 (10.6) 21.6 41.2Changes associated with prices(2)(95.3) (40.8) (18.1) (154.2)Year ended December 31, 2016$769.1 $417.1 $83.5 $1,269.7Changes associated with volumes(1)(25.5) (18.4) (8.5) (52.4)Changes associated with prices(2)195.8 95.3 36.9 328.0Year 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 endedDecember 31, 2017 and 2016, as compared to the years ended December 31, 2016 and 2015, by the respective volumes for the years endedDecember 31, 2017 and 2016. Pricing changes are driven by changes in commodity field-level prices, excluding the impact from commodityderivatives.A comparison of net realized average oil, gas and NGL prices, including the realized gains and losses on commodity derivative contracts, is provided in thefollowing table: Year Ended December 31, Change 2017 2016 2015 2017 vs 2016 2016 vs 2015Oil (per bbl) Average field-level price$47.88 $37.90 $42.59 $9.98 $(4.69)Commodity derivative impact0.34 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)61December 31, 2017 compared to December 31, 2016Oil 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 aresult 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 oilprices was driven by an increase in average NYMEX-WTI oil prices for the comparable period combined with narrowing differentials in our Northern Regionproperties. The 3% decrease in oil production volumes was primarily driven by a decrease in the Williston Basin due to a reduction in completion activity aswell as operational issues, under performance by certain wells, and well shut-ins associated with completion activity and a decrease in Pinedale due to thePinedale 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 aresult 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 gasprices was driven by an increase in average NYMEX-HH natural gas prices for the comparable period. The 5% decrease in production volumes was primarilydriven by the Pinedale Divestiture and a production decrease in the Uinta Basin due to reduced completion activity. These decreases were partially offset byincreased production in Haynesville/Cotton Valley due to a well refracturing program that began in 2016 and continued throughout 2017 on QEP operatedwells 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 wasprimarily 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 averagefield-level prices was primarily driven by an increase in propane, ethane and other NGL component prices. The 10% decrease in NGL production volumeswas 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, 2015Oil 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 aresult 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 oilprices 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 wasprimarily driven by an increase in the Permian Basin due to continued development drilling partially offset by a decrease in the Williston Basin due to fewernet 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 aresult 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 drivenby a decrease in average NYMEX-HH natural gas prices for the comparable period. The 2% decrease in production volumes was primarily driven byproduction 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 areadue to the continued divestitures of properties. These decreases were partially offset by increased production in the Williston Basin due to higher gasrecovery 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 wasprimarily a result of a 27% increase in production volumes, partially offset by an 18% decrease in average field-level prices. The 27% increase in NGLproduction volumes was primarily driven by increases in the Williston and Permian basins. The increase in the Williston Basin is due to additional ethanerecovered by a midstream provider and the increase in the Permian Basin is due to continued development drilling. These increases were partially offset bydecreases 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 refrigerationprocessing 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. The18% decrease in average field-level prices was driven by receiving an increased percentage of ethane from a midstream provider on our Williston Basinproduction during the year ended December 31, 2016 compared to the year ended December 31, 2015. The increased percentage of ethane was the result of amidstream provider electing to operate its gas processing plant in ethane recovery.Resale Margin and Storage ActivityQEP 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:62 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) $(519.6)Purchased oil and gas expense(64.3) (105.5) (626.8) 41.2 521.3Realized gains (losses) on gas storage derivative contracts— 2.9 3.8 (2.9) (0.9)Resale margin$(1.7) $(1.4) $(2.2) $(0.3) $0.8Purchased oil and gas sales and expense decreased during the year ended December 31, 2017, compared to the year ended December 31, 2016, due to lowerresale 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 thetermination 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 otherworking interest owner production. As such, QEP reported lower resale revenue and expenses in the year ended December 31, 2016, compared to 2015.Operating ExpensesThe 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 costs4.61 5.18 5.35 (0.57) (0.17)Production and property taxes2.15 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, 2016Lease 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. Theincrease was driven by an increase in workovers in the Williston and Permian basins and Haynesville/Cotton Valley, power and fuel expenses, and servicesand supplies expenses in the Permian Basin and increased water disposal expenses in Haynesville/Cotton Valley. These increases were partially offset by adecrease 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-Kfor more information).Transportation and processing costs. QEP's transportation and processing costs decreased $43.9 million, or $0.57 per Boe, during the year endedDecember 31, 2017 compared to 2016. The decrease in expense during 2017 was primarily attributable to decreases in Pinedale, primarily related to thePinedale Divestiture and recovery of historical transportation costs, and in Haynesville/Cotton Valley related to the recovery of fees for historical unutilizedgathering and transportation capacity that was charged to QEP by the operator of wells in which QEP had a working interest. These decreases were partiallyoffset 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 inLouisiana, where severance taxes are volume based. Production and property taxes increased $19.5 million, or $0.45 per Boe, during 2017, primarily a resultof increased oil and gas revenues primarily from higher field-level prices partially offset by lower production.63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/CottonValley 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. Thedecrease in the Williston Basin is the result of decreased production, partially offset by a rate increase from decreased proved reserves. The decrease in theUinta Basin is the result of decreased production and a rate decrease from increased proved reserves. The increases in Haynesville/Cotton Valley and thePermian 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 ofcharging $21.3 million of exploratory well costs related to the Central Basin Platform exploration project to exploration expense. During the third quarter of2017, based on well performance and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursuethe development of the Central Basin Platform exploration project. Refer to Note 3 – Capitalized Exploratory Well Costs, in Item 8 of Part II of this AnnualReport 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 ofimpairment charges recorded during 2016. Of the $78.9 million of impairment charges recorded during 2017, $38.1 million was related to impairment ofproved properties due to lower gas prices, $29.0 million was related to expiring leaseholds on unproved properties, an impairment of $6.5 million was relatedto an underground gas storage facility and $5.3 million related to an impairment of goodwill. Of the $38.1 million impairment of proved properties, $37.1million related to the Other Northern area and $1.0 million related to Louisiana properties. Of the $1,194.3 million of impairment charges recorded during2016, $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 leaseholdson 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 millionrelated to Pinedale properties, $4.7 million related to Uinta Basin properties, $3.4 million related to Other Northern properties and $0.6 million related toQEP'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 expensein 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 onsale 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 PinedaleDivestiture, 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 in2016 was primarily due to the continued divestitures of properties in the Other Southern area.December 31, 2016 compared to December 31, 2015Lease 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 decreasewas 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 ofcontinued divestitures of non-core properties and a decrease in the Uinta Basin due to lower maintenance and repair expenses, lower services and suppliesexpenses and lower workover expenses. These decreases were partially offset by an increase in the Williston Basin due to increased workovers, increasedproduced 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 endedDecember 31, 2016, compared to 2015. The decrease in expense during 2016 was primarily attributable to additional expenses incurred inHaynesville/Cotton Valley as a result of recognizing additional fees in 2015 related to unutilized gathering and transportation capacity that was charged toQEP 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 toincreased 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.64Depreciation, depletion and amortization. DD&A expense decreased $10.0 million during the year ended December 31, 2016, compared to 2015. Thedecrease in DD&A expense was due to decreases in Pinedale and the Williston Basin, partially offset by increases in the Permian Basin, Haynesville/CottonValley 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 offsetby an increase in production. The increases in Haynesville/Cotton Valley and the Uinta Basin were primarily due to increased rates due to a decrease inproved reserves as well as increased production in Haynesville/Cotton Valley, while the increase in the Permian Basin was primarily due to increasedproduction.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 ofproved 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 toan 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 toUinta Basin properties, $3.4 million related to Other Northern properties and $0.6 million related to Other Southern properties. Of the $55.6 million ofimpairment charges recorded during 2015, $39.3 million was related to impairment of proved properties due to lower future oil and gas prices, $2.0 millionwas related to expiring leaseholds on unproved properties and $14.3 million related to impairment of goodwill. Of the $39.3 million impairment on provedproperties, $20.2 million related to Other Southern properties, $18.4 million related to Other Northern properties and $0.7 million related to Permian Basinproperties.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 2016compared 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-basedcompensation, primarily due to an increase in the mark-to-market value of the Deferred Compensation Wrap Plan and CIP. These increases were partiallyoffset 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 onsale 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 continueddivestitures of non-core properties in the Other Southern area.Non-Operating ExpensesDecember 31, 2017 compared to December 31, 2016Realized and unrealized gains (losses) on derivative contracts. Gains and losses on derivative contracts are comprised of both realized and unrealized gainsand losses on QEP's commodity derivative contracts, which are marked-to-market each period. During the year ended December 31, 2017, gains oncommodity derivative instruments were $24.5 million, of which $69.9 million were unrealized gains on derivative contracts related to production and storagecontracts, $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 AnnualReport on Form 10-K for more information) and $15.5 million were realized losses. During 2016, losses on commodity derivative instruments were $233.0million, 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 to2016. The decrease was primarily the result of $22.6 million of bargain purchase gains recognized in 2016 that related to acquisitions which were accountedfor as a business combination under ASC 805, Business Combinations during the year ended December 31, 2016 (Refer to Note 2 – Acquisitions andDivestitures, in Item 8 of Part II of this Annual Report on Form 10-K for more information).65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 yearended 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 inincome 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 thefederal 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 endedDecember 31, 2017, compared to 36.3% for the year ended December 31, 2016.December 31, 2016 compared to December 31, 2015Realized 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 commodityderivative 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 to2015. The increase was primarily the result of $22.6 million of bargain purchase gains recognized related to acquisitions which were accounted for as abusiness combination under ASC 805, Business Combinations during the year ended December 31, 2016 (Refer to Note 2 – Acquisitions and Divestitures, inItem 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 secondquarter 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 Form10-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 yearended 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 inincome 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 of36.3% 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 stateincome tax rate change and a state return to provision adjustment.LIQUIDITY AND CAPITAL RESOURCESQEP 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 alevel of certainty to the Company's cash flows. QEP generally funds its operations and planned capital expenditures with cash flow from its operatingactivities, cash on hand and borrowings under its revolving credit facility. The Company expects that these sources of cash will be sufficient to fund itsoperations 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 Basinand Haynesville/Cotton Valley and, if successful, use the proceeds to fund on-going operations, reduce debt, repurchase shares and for general corporatepurposes. 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; paidfees and expenses associated with the repayment and used the remainder for general corporate purposes.66QEP received aggregate proceeds of approximately $806.8 million related to the Pinedale Divestiture and the sale of properties during the year endedDecember 31, 2017. All of the proceeds from the Pinedale Divestiture were used to close the 2017 Permian Basin Acquisition. QEP has made offers to variouspersons who own additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms andconditions as the original purchase. If all offers are accepted, QEP now expects that the aggregate purchase price will not exceed $50.0 million. In February2018, QEP entered into agreements for an aggregate purchase price of $36.1 million, subject to customary purchase price adjustments. The transactions andany 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 ofapproximately $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 incompliance with the covenants contained in its revolving credit facility. To the extent actual operating results, realized commodity prices or uses of cashdiffer from the Company's assumptions, QEP's liquidity could be adversely affected.Credit FacilityIn November 2017, QEP entered into the Seventh Amendment to its Credit Agreement, which, among other things, reduced the aggregate principal amount ofcommitments to $1.25 billion and extended the maturity date, subject to satisfaction of certain conditions, to September 1, 2022. The credit facility providesfor 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 thecredit 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 notexceed 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarter ending December 31, 2017, 4.00 times commencing withthe fiscal quarter ending March 31, 2018, through the fiscal quarter ending December 31, 2018, and 3.75 times thereafter, and (iii) during a ratings triggerperiod (as defined), a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.25times 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, andmust 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 noborrowings outstanding and $2.8 million in letters of credit outstanding under the credit facility. At February 23, 2018, QEP had $154.0 million ofborrowings outstanding and had $1.0 million of letters of credit outstanding under the credit facility and was in compliance with the covenants under thecredit agreement.Senior NotesDuring 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 torepay $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 2026.67Cash Flow from Operating ActivitiesCash flows from operating activities are primarily affected by oil, gas and NGL production volumes and commodity prices (including the effects ofsettlements of the Company's derivative contracts) and by changes in working capital. QEP enters into commodity derivative transactions covering asubstantial, 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 income335.8 1,794.1 1,193.4 (1,458.3) 600.7Changes in operating assets and liabilities(6.7) 114.6 (562.7) (121.3) 677.3Net cash provided by operating activities$598.4 $663.7 $481.3 $(65.3) $182.4Net cash provided by operating activities during the year ended December 31, 2017, decreased $65.3 million compared to 2016, which included a $1,514.3million increase in net income, a $1,458.3 million decrease in non-cash adjustments to net income and a $121.3 million decrease in cash from operatingassets 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 millionand 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 $20.6million decrease in other that predominantly included decreases in interest payable and asset retirement obligation as well as an increase in accountsreceivable 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 $1,095.6million increase in net loss, a $600.7 million increase in non-cash adjustments to the net loss and a $677.3 million increase in cash from operating assets andliabilities. During the year ended December 31, 2016, non-cash adjustments to net loss primarily included impairment expense of $1,194.3 million, DD&Aexpense of $871.1 million and unrealized losses on derivative contracts of $367.0 million, partially offset by a decrease in deferred income taxes of $651.3million. The increase in changes in operating assets and liabilities primarily included a decrease in accounts receivable of $95.3 million and a decrease inincome 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 decreasein accounts payable and accrued expenses of $50.3 million, primarily related to timing of payments and receipts.Cash Flow from Investing ActivitiesA 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 $546.9Property, plant and equipment capital expenditures1,219.8 530.1 1,011.9 689.7 (481.8)Total accrued capital expenditures2,035.0 1,175.3 1,110.2 859.7 65.1Change 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)68During the year ended December 31, 2017, on an accrual basis, the Company invested $1,219.8 million on property, plant and equipment capitalexpenditures, excluding property acquisitions, an increase of $689.7 million compared to 2016, primarily due to increased capital expenditures in thePermian Basin and Haynesville/Cotton Valley. In 2017, QEP's capital expenditures were $704.3 million in the Permian Basin (including midstreaminfrastructure of $95.9 million, primarily related to fresh water supply, produced water gathering, salt water disposal, gas and oil gathering and oil terminalfacilities), $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 UintaBasin. 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, whichwas primarily related to the 2017 Permian Basin Acquisition and included undeveloped leasehold acreage, producing wells and additional surface acreage inthe Permian Basin. These acquisitions were primarily funded with proceeds of approximately $806.8 million from the Pinedale Divestiture and the sale ofother 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 WillistonBasin, $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 totalpurchase 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 receivablebalance. The $645.2 million of acquisitions was primarily related to the 2016 Permian Basin Acquisition and also included acquisitions of additionalinterests in QEP operated wells and additional undeveloped leasehold acreage in the Permian and Williston basins. These acquisitions were funded withproceeds 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 millionin 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 OtherNorthern area and $3.4 million in the Other Southern area. In addition, during the year ended December 31, 2015, QEP acquired various oil and gasproperties, primarily in the Williston and Permian basins, for a total purchase price of $98.3 million, which included an acquisition of additional interests inQEP operated wells and undeveloped acreage. Partially offsetting the acquisition capital outflow was $21.8 million of cash proceeds from non-core assetdivestitures, 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 capitalexpenditures (excluding property acquisitions) with cash flow from operating activities, cash on hand and borrowings under the credit facility. The aggregatelevels of capital expenditures for 2018 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, oil, gas andNGL 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 ActivitiesDuring the year ended December 31, 2017, net cash provided by financing activities was $125.8 million compared to net cash provided by financingactivities of $583.1 million during the year ended December 31, 2016. During the year ended December 31, 2017, the Company issued 5.625% Senior Notesdue 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 Notesdue 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 endedDecember 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 andJune 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 cashbalances 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 originalissue discount and unamortized debt issuance costs). As of December 31, 2016, long-term debt consisted of $2,020.9 million total debt, of which $2,045.0million is senior notes and $24.1 million of net original issue discount and unamortized debt issuance costs.69Off-Balance Sheet ArrangementsQEP may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. At December 31, 2017, theCompany's material off-balance sheet arrangements included operating leases; drilling, gathering, processing, firm transportation and storage contracts; andundrawn 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 onQEP'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 CommitmentsIn the course of ordinary business activities, QEP enters into a variety of contractual cash obligations and other commitments. The following tablesummarizes 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 $1,150.0Interest on fixed-rate, long-term debt(2)633.3 119.9 119.9 117.0 93.7 82.4 100.4Drilling contracts5.6 5.6 — — — — —Gathering, processing, firm transportation,storage and other394.0 90.0 68.4 54.9 29.9 28.3 122.5Asset retirement obligations(3)214.1 7.5 6.1 6.8 4.2 6.4 183.1Operating leases41.0 7.0 7.2 7.4 7.4 7.2 4.8Total$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 ofPart 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 RetirementObligations, in Item 8 of Part II in this Annual Report on Form 10-K for additional information.Impact of Inflation/Deflation and PricingAll 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 andgas decrease, costs decline. Cost declines tend to lag and may not adjust downward in proportion to declining commodity prices. Historically, field-levelprices received for QEP's oil and gas production have been volatile. During each of the years ended December 31, 2017 and 2016, commodity pricesincreased from the previous year, while during the year ended December 31, 2015, commodity prices decreased from the previous year. Changes incommodity prices impact QEP's revenues, estimates of reserves, assessments of any impairment of oil and gas properties, as well as values of properties beingacquired or sold. Price changes have the potential to affect QEP's ability to raise capital, borrow money, and retain personnel.Critical Accounting EstimatesQEP's significant accounting policies are described in Note 1 – Summary of Significant Accounting Policies, in Item 8 of Part II of this Annual Report onForm 10-K. The Company's Consolidated Financial Statements are prepared in accordance with GAAP. The preparation of consolidated financial statementsrequires management to make assumptions and estimates that affect the reported results of operations and financial position. The following is a discussion ofthe accounting policies, estimates and judgments that management believes are most significant in the application of GAAP used in the preparation of theCompany's financial statements.70Oil, gas and NGL ReservesOne of the most significant estimates the Company makes is the estimate of oil, gas and NGL reserves. Oil, gas and NGL reserve estimates require significantjudgments in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may change substantiallyover 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. Thesubjective judgments and variances in data for various fields make these estimates less precise than other estimates included in the financial statementdisclosures.Estimates of proved oil, gas and NGL reserves significantly affect the Company's DD&A expense. For example, if estimates of proved reserves decline, theCompany'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 animpairment analysis to determine if the carrying amount of oil and gas properties exceeds fair value and could result in an impairment charge, which wouldreduce 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 acomplex and highly interpretive process that is subject to continuous revision as additional production and development drilling information becomesavailable. 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 OperationsThe 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. Otherexploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessfulexploratory well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred. A gain or loss is generally recognizedonly when an entire field is sold or abandoned, or if the unit-of-production DD&A rate would be significantly affected. Capitalized costs of unprovedproperties are reclassified to proved property when related proved reserves are determined or charged against the impairment allowance when abandoned.Capitalized Exploratory Well CostsThe Company capitalizes exploratory well costs until it determines whether an exploratory well is commercial or noncommercial. If the Company deems thewell commercial, capitalized costs are depreciated on a field basis using the unit-of-production method and the estimated proved developed oil, gas and NGLreserves. If the Company concludes that the well is noncommercial, well costs are immediately charged to exploration expense. Exploratory well costs thathave been capitalized for a period greater than one year since the completion of drilling are expensed unless the Company remains engaged in substantialactivities to assess whether the well is commercial.Impairment of Long-Lived AssetsProved 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 ingroups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cashflows 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 NGLreserves caused by mechanical problems, faster-than-expected decline of production, lease ownership issues and declines in oil, gas and NGL prices. Ifimpairment is indicated, fair value is estimated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many yearsinto the future for a variety of factors, including commodity prices, operating costs and estimates of proved, probable and possible reserves. Cash flowestimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors. During the years endedDecember 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 ofits higher cost, proved properties in both of its Northern and Southern regions, due to lower forward prices.71Unproved properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments ofunproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, theCompany considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable explorationactivity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term. During the years endedDecember 31, 2017, 2016 and 2015, QEP recorded impairment charges of $29.0 million, $17.9 million and $2.0 million respectively, related to its unprovedproperties. The 2017 unproved property impairment charges primarily resulted from unproved leasehold acreage in the Central Basin Platform. Refer to Note3 – 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 unprovedproperty impairment charges primarily resulted from lower forward prices and expiring leaseholds.Asset Retirement ObligationsQEP records asset retirement obligations (ARO) associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarilyto abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel basedon abandonment costs of similar assets and depreciated over the life of the related assets. ARO is subject to revisions because of the intrinsic uncertaintiespresent when estimating asset retirement costs and asset retirement settlement dates. Revisions to the ARO estimate can result from changes in expected cashflows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculationusing 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 makeestimates over a long period, (ii) laws and regulations could change in the future and/or circumstances affecting QEP's operations could change, either ofwhich 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 requiresmanagement to estimate projected cash flows, make long-term assumptions about inflation rates, determine its credit-adjusted risk-free interest rates anddetermine 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 resultsof operations.Revenue RecognitionQEP recognizes revenue from oil and gas producing activities in the period that services are provided or products are delivered. Revenues associated with thesale 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. Revenuesinclude estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators. An imbalance liabilityis 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 storageactivities. QEP recognizes revenue from these resale activities when title transfers to the customer.Litigation and Other ContingenciesThe 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 potentialaccrual in its Consolidated Financial Statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when itsoccurrence is probable and damages can be reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range ofpossible outcomes.Legal proceedings are inherently unpredictable, and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires judgmentsabout uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a numberof factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoingdiscovery and/or development of information important to the matter. Refer to Note 9 – Commitments and Contingencies, in Item 8 of Part II of this AnnualReport on Form 10-K for additional information regarding litigation and other contingencies.72Environmental ObligationsManagement 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 reasonableestimates of the liability can be made. Estimates of environmental liabilities are based on a variety of factors, including, but not limited to, the stage ofinvestigation, 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, changesin the interpretation or administration of laws and regulations, revisions to the remedial design, unanticipated construction problems, identification ofadditional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment and technology. Consequently, it is not possiblefor management to reliably estimate the amount and timing of all future expenditures related to environmental matters and actual costs may varysignificantly. Refer to Note 9 – Commitments and Contingencies, in Item 8 of Part II of this Annual Report on Form 10-K for additional informationregarding current environmental claims.Derivative ContractsThe Company uses commodity derivative instruments, typically fixed-price swaps and costless collars, to reduce the impact of potential downwardmovements in commodity prices. Accounting rules for derivatives require marking these instruments to fair value at the balance sheet reporting date. TheCompany follows mark-to-market accounting and recognizes all gains and losses on such instruments in earnings in the period in which they occur. As aresult, changes in the fair value of QEP's commodity derivative instruments could have a significant impact on net income. QEP does not engage inspeculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. Refer toNote 6 – Derivative Contracts, in Item 8 of Part II of this Annual Report on Form 10-K for additional information.Pension and Other Postretirement BenefitsQEP maintains closed, defined-benefit pension and other postretirement benefit plans, including both a qualified and a supplemental plan. QEP also providescertain health care and life insurance benefits for certain retired QEP employees. Determination of the benefit obligations for QEP's defined-benefit pensionand other postretirement benefit plans impacts the recorded amounts for such obligations on the Consolidated Balance Sheets and the amount of benefitexpense 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 variousassumptions. Critical assumptions for pension and other postretirement benefit plans include the discount rate, the expected rate of return on plan assets (forfunded pension plans) and the rate of future compensation increases. Other assumptions involve demographic factors such as retirement, mortality andturnover. QEP evaluates and updates its actuarial assumptions at least annually. QEP recognizes a pension curtailment immediately when there is asignificant reduction in, or an elimination of, defined-benefit accruals for present employees' future services. Refer to Note 11 – Employee Benefits, in Item 8of Part II of this Annual Report on Form 10-K for additional information.Share-Based CompensationQEP issues stock options, restricted share awards and restricted share units to certain officers, employees and non-employee directors under its Long-TermStock 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 acceleratedmethod in recognizing share-based compensation costs for stock options and restricted share awards with graded-vesting periods. Stock options held byemployees generally vest in three equal, annual installments and primarily have a term of seven years. Restricted share awards and restricted share units vestin equal installments over a specified number of years after the grant date with the majority vesting in three years. Non-vested restricted share awards havevoting and dividend rights; however, sale or transfer is restricted. Employees may elect to defer their grants of restricted share awards and these deferredawards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified unfundeddeferred compensation plan at the time of vesting. The Company also awards performance share units under its Cash Incentive Plan (CIP) that are generallypaid 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 compensationcost 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-BasedCompensation, in Item 8 of Part II of this Annual Report on Form 10-K for additional information.73Income TaxesThe amount of income taxes recorded by QEP requires interpretations of complex rules and regulations of various tax jurisdictions throughout the UnitedStates. QEP has recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. QEP routinely assessesthe 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 deferredtax assets will not be realized. QEP routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. The accruals fordeferred tax assets and liabilities, including deferred state income tax assets and liabilities, are subject to significant judgment by management and arereviewed and adjusted routinely based on changes in facts and circumstances. Although management considers its tax accruals adequate, material changes inthese 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 arestill 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 benefitour 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 additionalinformation.Purchase Price AllocationsQEP 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 basedon 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 abargain purchase gain or goodwill. The amount of goodwill or bargain purchase gain recorded in any particular business combination can vary significantlydepending 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 significantassumptions relate to the estimated fair values assigned to proved and unproved oil and gas properties. If sufficient market data is not available regarding thefair values of proved and unproved properties, QEP must prepare estimates. To estimate the fair values of these properties, QEP utilizes a discounted cash flowmodel which utilizes the following inputs to estimate future net cash flows: estimated quantities of oil, gas and NGL reserves; estimates of future commodityprices; 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. Themarket-based weighted-average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk ofestimating and valuing unproved reserves, when a discounted cash flow model is used, the discounted future net cash flows of probable and possible reservesare reduced by additional risk factors. In some instances, market comparable information of recent transactions is used to estimate fair value of unprovedacreage.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 propertyresults 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 thoseoriginally 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 Note2 – 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 DevelopmentsSee 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.74ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKQEP'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 cashflows from operating, investing and financing activities. Commodity prices have historically been volatile and are subject to wide fluctuations in response torelatively 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 thecontractual capacity of these transportation commitments. In addition, additional non-cash impairment expense of the Company's oil and gas properties maybe required if future oil and gas commodity prices experience a significant decline. Furthermore, the Company's revolving credit facility has a floatinginterest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. To partially manage the Company's exposure to these risks, QEPenters into commodity derivative contracts in the form of fixed-price and basis swaps and collars to manage commodity price risk and periodically enters intointerest rate swaps to manage interest rate risk.Commodity Price Risk ManagementQEP uses commodity derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, thesearrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Companyare fixed-price and basis swaps and collars. The volume of commodity derivative instruments utilized by the Company may vary from year to year based onQEP's forecasted production. The Company's current derivative instruments do not have margin requirements or collateral provisions that would requirepayments prior to the scheduled cash settlement dates. As of December 31, 2017, QEP held commodity price derivative contracts totaling 24.8 million barrelsof 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 contractstotaling 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, inItem 8 of Part II of this Annual Report on Form 10-K for open derivative positions as of December 31, 2017.Production Commodity Derivative SwapsYear Index Total Volumes Average Swap Price per Unit (in millions) Oil sales (bbls) ($/bbl)2018 NYMEX WTI 15.4 $52.482019 NYMEX WTI 9.1 $52.45Gas sales (MMBtu) ($/MMBtu)2018 (Full Year) NYMEX HH 91.8 $2.992018 (July through December) NYMEX HH 1.8 $3.012019 NYMEX HH 43.8 $2.86Production Commodity Derivative Basis SwapsYear Index Less Differential Index Total Volumes Weighted-AverageDifferential (in millions) Oil sales (bbls) ($/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 $(0.16)75Changes in the fair value of derivative contracts from December 31, 2016 to December 31, 2017, are presented below: Commodityderivative contracts (in millions)Net fair value of oil and gas derivative contracts outstanding at December 31, 2016$(201.8)Contracts settled15.5Change in oil and gas prices on futures markets150.5Contracts 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 derivativeinstruments. For additional information regarding the Company's commodity derivative transactions, refer to Note 6 – Derivative Contracts, in Item 8 of PartII of this Annual Report on Form 10-K.Interest Rate Risk ManagementThe 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, asdescribed 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 creditfacility. As of December 31, 2016, QEP had no borrowings outstanding under the credit facility. If interest rates were to increase or decrease 10% during theyear ended December 31, 2017, at our average level of borrowing for those same periods, the Company's interest expense would increase or decrease by $0.1million 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. Foradditional 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.76ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAFinancial Statements:Page No.Report of Independent Registered Public Accounting Firm as of and for the years ended December 31, 2017, 2016 and 201578Consolidated Statements of Operations for the three years ended December 31, 201780Consolidated Statements of Comprehensive Income (Loss) for the three years ended December 31, 201781Consolidated Balance Sheets as of December 31, 2017 and 201682Consolidated Statements of Equity for the three years ended December 31, 201783Consolidated Statements of Cash Flows for the three years ended December 31, 201784Notes Accompanying the Consolidated Financial Statements85All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notesthereto.77Report of Independent Registered Public Accounting FirmTo the Board of Directors and Shareholders of QEP Resources, Inc.Opinions on the Financial Statements and Internal Control over Financial ReportingWe have audited the accompanying consolidated balance sheets of QEP Resources, Inc. and its subsidiaries as of December 31, 2017 and 2016, and therelated consolidated statements of operations, comprehensive income (loss), equity and cash flows for each of the three years in the period ended December31, 2017, including the related notes (collectively referred to as the "consolidated financial statements"). We also have audited the Company's internalcontrol over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by theCommittee of Sponsoring Organizations of the Treadway Commission (COSO).In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as ofDecember 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, 2017 inconformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all materialrespects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – IntegratedFramework (2013) issued by the COSO.Basis for OpinionsThe Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, andfor its assessment of the effectiveness of internal control over financial reporting, included in Management's Assessment of Internal Control over FinancialReporting appearing under Item 9A. Our responsibility is to express opinions on the Company's consolidated financial statements and on the Company'sinternal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting OversightBoard (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and theapplicable 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 reasonableassurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internalcontrol over financial reporting was maintained in all material respects.Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financialstatements, 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 consolidated financial statements. Our audits also included evaluating the accounting principles usedand significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internalcontrol over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weaknessexists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performingsuch 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 ReportingA company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal controlover financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are beingmade only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.78Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate./s/ PricewaterhouseCoopers LLPDenver, ColoradoFebruary 28, 2018We have served as the Company's auditor since 2012.79QEP RESOURCES, INC.CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, 2017 2016 2015REVENUES(in millions, except per share amounts)Oil sales$939.4 $769.1 $834.2Gas sales494.0 417.1 468.5NGL sales111.9 83.5 80.0Other revenues15.0 6.2 15.1Purchased oil and gas sales62.6 101.2 620.8Total Revenues1,622.9 1,377.1 2,018.6OPERATING EXPENSES Purchased oil and gas expense64.3 105.5 626.8Lease operating expense294.8 224.7 238.8Transportation and processing costs245.3 289.2 291.3Gathering and other expense7.3 5.0 5.8General and administrative153.5 196.5 168.0Production and property taxes114.3 94.8 117.6Depreciation, depletion and amortization754.5 871.1 881.1Exploration expenses22.0 1.7 2.7Impairment78.9 1,194.3 55.6Total Operating Expenses1,734.9 2,982.8 2,387.7Net gain (loss) from asset sales213.5 5.0 4.6OPERATING INCOME (LOSS)101.5 (1,600.7) (364.5)Realized and unrealized gains (losses) on derivative contracts (Note 6)24.5 (233.0) 277.2Interest 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) benefit312.2 708.2 93.6NET 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) $(0.85) Weighted-average common shares outstanding Used in basic calculation240.6 221.7 176.6Used in diluted calculation240.6 221.7 176.6Dividends per common share$— $— $0.08Refer to Notes accompanying the Consolidated Financial Statements.80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 8.2Amortization of net actuarial (gain) loss(5)0.3 0.5 0.3Net curtailment and settlement cost incurred(6)0.4 — 4.5Other comprehensive income (loss)5.6 (4.3) 11.9Comprehensive 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 torevalue 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 yearended 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 $0.3million 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 $2.6 million for the years ended December 31, 2017 and 2015, respectively.Refer to Notes accompanying the Consolidated Financial Statements.81QEP RESOURCES, INC.CONSOLIDATED BALANCE SHEETS December 31, 2017 December 31, 2016ASSETS(in millions)Current Assets Cash and cash equivalents$— $443.8Accounts receivable, net142.1 155.7Income tax receivable4.9 18.6Fair value of derivative contracts3.4 —Hydrocarbon inventories, at lower of average cost or net realizable value3.6 10.4Prepaid expenses10.7 11.4Other current assets0.7 0.2Total Current Assets165.4 640.1Property, Plant and Equipment (successful efforts method for oil and gas properties) Proved properties12,470.9 14,232.5Unproved properties1,095.8 871.5Gathering and other319.7 301.8Materials and supplies37.8 32.7Total Property, Plant and Equipment13,924.2 15,438.5Less Accumulated Depreciation, Depletion and Amortization Exploration and production6,642.9 8,797.7Gathering and other124.3 101.8Total Accumulated Depreciation, Depletion and Amortization6,767.2 8,899.5Net Property, Plant and Equipment7,157.0 6,539.0Fair value of derivative contracts0.1 —Other noncurrent assets72.3 66.3TOTAL ASSETS$7,394.8 $7,245.4 LIABILITIES AND EQUITY Current Liabilities Checks outstanding in excess of cash balances$44.0 $12.3Accounts payable and accrued expenses372.1 269.7Production and property taxes31.6 30.1Interest payable26.0 32.9Fair value of derivative contracts103.6 169.8Total Current Liabilities577.3 514.8Long-term debt2,160.8 2,020.9Deferred income taxes518.0 825.9Asset retirement obligations206.6 225.8Fair value of derivative contracts31.8 32.0Other long-term liabilities102.4 123.3Commitments and Contingencies (Note 9) EQUITY Common stock - par value $0.01 per share; 500.0 million shares authorized; 243.0 million and 240.7million shares issued, respectively2.4 2.4Treasury stock - 2.0 million and 1.1 million shares, respectively(34.2) (22.9)Additional paid-in capital1,398.2 1,366.6Retained earnings2,442.6 2,173.3Accumulated other comprehensive income (loss)(11.1) (16.7)Total Common Shareholders' Equity3,797.9 3,502.7TOTAL LIABILITIES AND EQUITY$7,394.8 $7,245.4 Refer to Notes accompanying the Consolidated Financial Statements.82QEP RESOURCES, INC.CONSOLIDATED STATEMENTS OF EQUITY Common Stock Treasury Stock AdditionalPaid-inCapital RetainedEarnings Accumulated OtherComprehensiveIncome(Loss) Total Shares Amount Shares Amount (in millions)Balance at December 31, 2014176.2 $1.8 (0.8) $(25.4) $535.3 $3,587.9 $(24.3) $4,075.3Net income (loss)— — — — — (149.4) — (149.4)Dividends paid— — — — — (14.1) — (14.1)Share-based compensation1.1 — 0.3 10.8 19.5 (6.1) — 24.2Change in pension and postretirement liability,net of tax— — — — — — 11.9 11.9Balance at December 31, 2015177.3 1.8 (0.5) (14.6) 554.8 3,418.3 (12.4) 3,947.9Net income (loss)— — — — — (1,245.0) — (1,245.0)Equity issuance, net of offering costs61.0 0.6 — — 780.8 — — 781.4Share-based compensation2.4 — (0.6) (8.3) 31.0 — — 22.7Change in pension and postretirement liability,net of tax— — — — — — (4.3) (4.3)Balance at December 31, 2016240.7 2.4 (1.1) (22.9) 1,366.6 2,173.3 (16.7) 3,502.7Net income (loss)— — — — — 269.3 — 269.3Share-based compensation2.3 — (0.9) (11.3) 31.6 — — 20.3Change in pension and postretirement liability,net of tax— — — — — — 5.6 5.6Balance at December 31, 2017243.0 $2.4 (2.0) $(34.2) $1,398.2 $2,442.6 $(11.1) $3,797.9Refer to Notes accompanying the Consolidated Financial Statements.83QEP RESOURCES, INC.CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2017 2016 2015OPERATING 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 amortization754.5 871.1 881.1Deferred income taxes(314.8) (651.3) 25.3Impairment78.9 1,194.3 55.6Dry hole exploratory well expense21.3 — —Share-based compensation22.4 35.6 34.7Pension curtailment loss— — 11.2Amortization of debt issuance costs and discounts6.2 6.4 6.2Bargain purchase gain from acquisitions0.4 (22.6) —Net (gain) loss from asset sales(213.5) (5.0) (4.6)Loss from early extinguishment of debt32.7 — —Unrealized (gains) losses on marketable securities(2.9) (1.4) 0.2Unrealized (gains) losses on derivative contracts(40.0) 367.0 183.7Other non-cash activity(9.4) — —Changes in operating assets and liabilities Accounts receivable(2.0) 95.3 124.6Hydrocarbon inventories(1.1) 8.7 15.5Prepaid expenses(0.2) 18.5 16.7Accounts payable and accrued expenses3.5 (50.3) (34.5)Federal income taxes receivable13.7 68.7 (619.4)Other(20.6) (26.3) (65.6)Net Cash Provided by (Used in) Operating Activities598.4663.7481.3INVESTING 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 assets806.8 29.0 21.8Net Cash Provided by (Used in) Investing Activities(1,168.0) (1,179.1) (1,217.6)FINANCING ACTIVITIES Checks outstanding in excess of cash balances31.7 (17.5) (24.9)Long-term debt issued500.0 — —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 facility492.0 — —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 Activities125.8 583.1 (47.7)Change in cash and cash equivalents(443.8) 67.7 (784.0)Beginning cash and cash equivalents443.8 376.1 1,160.1Ending cash and cash equivalents$— $443.8 $376.1Refer to Notes accompanying the Consolidated Financial Statements.84QEP RESOURCES, INC.NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTSNote 1 – Summary of Significant Accounting PoliciesNature of BusinessQEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: theNorthern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the contextotherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporateheadquarters 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 ConsolidationThe Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Consolidated FinancialStatements were prepared in accordance with GAAP and with the instructions for annual reports on Form 10-K and Regulations S-X. All significantintercompany 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 AgreementsEffective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP MarketingCompany (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and saleagreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storageactivities and Haynesville Gathering. As a result, QEP Energy directly markets its own oil, gas and NGL production. While QEP continues to act as an agentfor 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 thisproduction. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had prior to2016.In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic280, Segment Reporting, and determined that QEP had one reportable segment effective January 1, 2016. The Company has recast its financial statements forhistorical periods to reflect the impact of the termination of marketing agreements to show its financial results without segments.ReclassificationsCertain prior period amounts on the Consolidated Statements of Operations, Consolidated Balance Sheets and Consolidated Statements of Cash Flows havebeen reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's net income (loss), earnings (loss) pershare, cash flows, current assets or retained earnings previously reported.Use of EstimatesThe preparation of the Consolidated Financial Statements and Notes in conformity with GAAP requires that management formulate estimates andassumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requiresmanagement's estimates and assumptions is the estimate of proved oil, gas and NGL reserves, which are used in the calculation of depreciation, depletion andamortization rates of its oil and gas properties, impairment of proved properties and asset retirement obligations. Changes in estimated quantities of itsreserves could impact the Company's reported financial results as well as disclosures regarding the quantities and value of proved oil and gas reserves. Otheritems subject to estimates and assumptions include the carrying amount of property, plant and equipment, assigning fair value and allocating purchase pricein 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 arereasonable, actual results could differ from these estimates.85Risks and UncertaintiesThe Company's revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil, gas and NGL, which areaffected by many factors outside of QEP's control, including changes in market supply and demand. Changes in market supply and demand are impacted byweather 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. TheCompany's derivative contracts serve to mitigate in part the effect of this price volatility on the Company's cash flows, and the Company has derivativecontracts 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 gascommodity derivative contracts.Revenue RecognitionQEP recognizes revenue from oil and gas producing activities in the period that services are provided or products are delivered. Revenues associated with thesale of oil, gas and NGL are accounted for using the sales method, whereby revenue is recognized when these commodities are sold to purchasers. Revenuesinclude estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators. An imbalance liabilityis 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 storageactivities. QEP recognizes revenue from these resale activities when title transfers to the customer.Cash and Cash Equivalents and Restricted CashCash equivalents consist principally of highly liquid investments in securities with original maturities of three months or less made through commercial bankaccounts 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 $443.8million 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 thirdparties 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 2015Supplemental Disclosures(in millions)Cash paid for interest, net of capitalized interest$134.9 $139.1 $139.4Cash paid (refund received) for income taxes, net$(0.3) $(123.5) $487.8Non-cash investing activities Change in capital expenditure accrual balance$60.2 $(32.8) $(129.2)Accounts ReceivableAccounts receivable consists mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivablesfrom 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 periodof time, the Company could incur increased levels of bad debt expense. Recovery of bad debt associated with accounts receivable for the year endedDecember 31, 2017 was $1.0 million. Bad debt expense associated with accounts receivable for the years ended December 31, 2016 and 2015, was $1.8million, and $0.5 million, respectively. Bad debt recovery or expense is included in "General and administrative" expense on the Consolidated Statements ofOperations. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. The allowance forbad debt expenses was $1.6 million at December 31, 2017, and $4.8 million at December 31, 2016.86Property, Plant and EquipmentProperty, 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 OperationsThe 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. Otherexploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessfulexploratory well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred. A gain or loss is generally recognizedonly 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 impairmentallowance when abandoned.Capitalized Exploratory Well CostsThe Company capitalizes exploratory well costs until it determines whether an exploratory well is commercial or noncommercial. If the Company deems thewell commercial, capitalized costs are depreciated on a field basis using the unit-of-production method and the estimated proved developed oil and gasreserves. If the Company concludes that the well is noncommercial, well costs are immediately charged to exploration expense. Exploratory well costs thathave been capitalized for a period greater than one year since the completion of drilling are expensed unless the Company remains engaged in substantialactivities 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 futureabandonment 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 theestimated useful lives of those assets using the straight-line method. The estimated useful lives of those assets depreciated under the straight-line basisgenerally range as follows:Buildings10 to 30 yearsLeasehold improvements3 to 10 yearsService, transportation and field service equipment3 to 7 yearsFurniture and office equipment3 to 7 yearsImpairment of Long-Lived AssetsProved 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 ingroups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cashflows 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 NGLreserves caused by mechanical problems, faster-than-expected decline of production, lease ownership issues, and declines in oil, gas and NGL prices. Ifimpairment is indicated, fair value is estimated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many yearsinto the future for a variety of factors, including commodity prices, operating costs and estimates of proved, probable and possible reserves. Cash flowestimates 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 ofunproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, theCompany considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable explorationactivity 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 tolower future gas prices, $29.0 million was primarily related to unproved leasehold acreage in the Central Basin Platform (Refer to Note 3 – CapitalizedExploratory Well Costs for additional information), $6.5 million was related to impairment of an underground gas storage facility and $5.3 million wasrelated to the impairment of goodwill. Of the $38.1 million impairment of proved properties, $37.1 million related to the Other Northern area and $1.0million 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 propertiesdue 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 impairmentof 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 Basinproperties, $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 tolower 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 ofgoodwill. Of the $39.3 million impairment on proved properties, $20.2 million related to QEP's remaining Other Southern properties, $18.4 million relatedOther Northern properties, and $0.7 million related to Permian Basin properties.Asset Retirement ObligationsQEP is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company's ARO liability applies primarily to abandonmentcosts associated with oil and gas wells and certain other properties. ARO associated with the retirement of tangible long-lived assets are recognized asliabilities 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 assetretirement costs, is depreciated over the useful life of the asset. ARO are recorded at estimated fair value, measured by reference to the expected future cashoutflows required to satisfy the retirement obligations discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognizedover time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded toboth the ARO liability and the long-lived asset. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimatedinflation rates and changes in the estimated timing of abandonment. Refer to Note 4 – Asset Retirement Obligations for additional information.GoodwillGoodwill represents the excess of the amount paid over the fair value of assets acquired in a business combination and is not subject to amortization. Duringthe year ended December 31, 2017, QEP early adopted ASU 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwillimpairment. 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 fairvalue 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 expectedfuture cash flows. Key assumptions used in the cash flow model include estimated quantities of oil, gas and NGL reserves, including both proved reserves andrisk-adjusted unproved reserves, and including probable and possible reserves; estimates of market prices considering forward commodity price curves as ofthe 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 thefourth quarter of 2017, QEP performed an annual impairment test over goodwill as described above, which resulted in a full write down of goodwill of $5.3million.During the years ended December 31, 2016 and 2015, QEP recorded $3.7 million and $14.3 million, respectively, of goodwill. Annual impairment tests overgoodwill at year end December 31, 2016 and 2015 resulted in a full write down of $3.7 million and $14.3 million, respectively.88Litigation and Other ContingenciesThe 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 accrualin its Consolidated Financial Statements. The amount of ultimate loss may differ from these estimates. In accordance with ASC 450, Contingencies, anaccrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated mostlikely 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 forestimated 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 discountedto their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of suchrecoveries is probable.Derivative ContractsQEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. QEP uses commodityderivative instruments, typically fixed-price swaps and costless collars to realize a known price or price range for a specific volume of production deliveredinto a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. Alltransactions 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-termdifferences in price. Additionally, QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisionsthat 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 inthe month of settlement and are also marked-to-market monthly. Refer to Note 6 – Derivative Contracts for additional information.Credit RiskManagement believes that its credit review procedures, loss reserves, cash deposits and investments, and collection procedures have adequately provided forusual and customary credit-related losses. Exposure to credit risk may be affected by extended periods of low commodity prices, as well as the concentrationof customers in certain regions due to changes in economic or other conditions. Customers include commercial and industrial enterprises and financialinstitutions 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 andcounterparty credit fundamentals, including public credit ratings, where available. Credit exposure is controlled through credit approvals and limits based oncounterparty credit fundamentals, and is aggregated across all lines of business, including derivatives, physical exposure and short-term cash investments. Tofurther manage the level of credit risk, the Company requests credit support and, in some cases, requests parental guarantees, letters of credit or prepaymentfrom companies with perceived higher credit risk. Loss reserves are periodically reviewed for adequacy and may be established on a specific case basis. TheCompany 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 toexecuting derivative contracts. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence ofdefined acts of default by either the Company or counterparty to a derivative contract. The Company routinely monitors and manages its exposure tocounterparty risk related to derivative contracts by requiring specific minimum credit standards for all counterparties, actively monitoring counterpartiespublic credit ratings, and avoiding concentration of credit exposure by transacting with multiple counterparties. The Company's commodity derivativecontract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings.89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 EnergyCompany 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'stotal revenues. During the year ended December 31, 2015, no customer accounted for 10% or more of QEP's total revenues. Management believes that theloss 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 arenumerous potential purchasers of its production.Income TaxesThe amount of income taxes recorded by QEP requires interpretations of complex rules and regulations of various tax jurisdictions throughout the UnitedStates. QEP has recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. Deferred income taxesare 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 bereflected 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 realizedupon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement andbelieves 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 forecastfuture income in Oklahoma and Louisiana to offset net operating losses before they expire. All federal income tax returns prior to 2017 have been examinedby 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 yearsremain 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 thelargest amount that is more-likely-than-not to be sustained upon examination by the relevant taxing authorities. Our policy is to recognize any interestearned on income tax refunds in "Interest and other income (expense)" on the Consolidated Statements of Operations, any interest expense related touncertain tax positions in "Interest expense" on the Consolidated Statements of Operations and to recognize any penalties related to uncertain tax positionsin "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 interestexpense 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 ofestimated 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 incometax 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 rateof 21% compared to 35%. The Tax Legislation also repeals the corporate alternative minimum tax (AMT). Several provisions of the new tax law such aslimitations on the deductibility of interest expense and certain executive compensation and the inability to use Section 1031 like-kind exchanges for assetssuch as machinery and equipment could apply to QEP; however, we do not believe that they will materially impact QEP's financial statements. The impact ofthe Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made andactions the Company may take as a result of the Tax Legislation. Additionally, guidance issued by the relevant regulatory authorities regarding the TaxLegislation may materially impact QEP's financial statements. The Company will continue to analyze the Tax Legislation to determine the full impact of thenew law, on the Company's consolidated financial statements and operations.Treasury StockWe record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders' equity inthe Consolidated Balance Sheets. QEP acquires treasury stock from stock forfeitures and withholdings and uses the acquired treasury stock for stock optionexercises and certain stock grants to employees; refer to Note 10 – Share-Based Compensation for additional information.90Earnings (Loss) Per ShareBasic earnings (loss) per share (EPS) are computed by dividing net income (loss) by the weighted-average number of common shares outstanding during thereporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stockoptions. QEP's unvested restricted share awards are included in weighted-average basic common shares outstanding because, once the shares are granted, therestricted share awards are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted share awards are eligible to receivedividends.Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and areincluded 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 unvestedrestricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not containrights to dividends. Under the two-class method, the earnings used to determine basic earnings (loss) per common share are reduced by an amount allocatedto participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are notobligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) percommon 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 0.1million 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 outstanding240.6 221.7 176.6Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan— — —Average diluted common shares outstanding240.6 221.7 176.6Share-Based CompensationQEP issues stock options, restricted share awards and restricted share units to certain officers, employees and non-employee directors under its Long-TermStock 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 acceleratedmethod in recognizing share-based compensation costs for stock options and restricted share awards with graded-vesting periods. Stock options held byemployees generally vest in three equal, annual installments and primarily have a term of seven years. Restricted share awards and restricted share units vestin equal installments over a specified number of years after the grant date with the majority vesting in three years. Non-vested restricted share awards havevoting and dividend rights; however, sale or transfer is restricted. Employees may elect to defer their grants of restricted share awards and these deferredawards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified unfundeddeferred compensation plan at the time of vesting. The Company also awards performance share units under its CIP that are generally paid out in cashdepending upon the Company's total shareholder return compared to a group of its peers over a three-year period. Share-based compensation cost for theperformance 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.91Pension and Other Postretirement BenefitsQEP maintains closed, defined-benefit pension and other postretirement benefit plans, including both a qualified and a supplemental plan. QEP also providescertain health care and life insurance benefits for certain retired QEP employees. Determination of the benefit obligations for QEP's defined-benefit pensionand other postretirement benefit plans impacts the recorded amounts for such obligations on the Consolidated Balance Sheets and the amount of benefitexpense 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 variousassumptions. Critical assumptions for pension and other postretirement benefit plans include the discount rate, the expected rate of return on plan assets (forfunded pension plans) and the rate of future compensation increases. Other assumptions involve demographic factors such as retirement, mortality andturnover. QEP evaluates and updates its actuarial assumptions at least annually. QEP recognizes a pension curtailment immediately when there is asignificant reduction in, or an elimination of, defined-benefit accruals for present employees' future services. Refer to Note 11 – Employee Benefits foradditional 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 ofother comprehensive income. Other comprehensive income (loss) includes certain items that are recorded directly to equity and classified as accumulatedother comprehensive income (AOCI), which includes changes in the underfunded portion of the Company's defined-benefit pension and other postretirementbenefits plans and changes in deferred income taxes on such amounts. These transactions do not represent the culmination of the earnings process but resultfrom periodically adjusting historical balances to fair value.Recent Accounting DevelopmentsIn May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts withCustomers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparabilitywithin industries, across industries and across capital markets. The revenue standard contains principles that an entity will apply to determine themeasurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goodsor 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 enhanceddisclosures will be required. The amendment is effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption ispermitted for periods beginning on or after December 15, 2016. The two permitted transition methods under the new standard are the full retrospectivemethod, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case thecumulative effect of applying the standard would be recognized at the date of initial application. The Company does not expect net income (loss) or cashflows to be materially impacted by the new standard; however, the Company expects that a portion of its transportation and processing costs will be nettedwithin revenue under the new standard. In addition, the Company will have expanded disclosure requirements, as a result of the adoption of the ASU. TheCompany 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 asoperating leases on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The amendment will be effectivefor reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on theCompany'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, whichclarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly andclosely related to their debt hosts. The amendment was effective prospectively for reporting periods beginning on or after December 15, 2016, and earlyadoption 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 impacton the Company's Consolidated Financial Statements.92In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based paymentaccounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for andpresented in the financial statements. This amendment was effective prospectively for reporting periods beginning after December 15, 2016, and earlyadoption 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 impacton 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 , whichintends to reduce the diversity in practice in how certain transactions are classified in the statement of cash flows. This amendment will be effectiveretrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in thefourth 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 thedefinition 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 ispermitted. 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 theCompany's Consolidated Financial Statements; however, this standard may impact the determination of whether future acquisitions are accounted for as abusiness 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, whicheliminates the requirement to calculate implied fair value of goodwill to measure the goodwill impairment charge. The amendment will be effectiveprospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company early adopted this standard in the firstquarter 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 pensioncost and net periodic postretirement benefit cost, which changes how employers of a defined benefit plan present net periodic benefit cost in the statementsof operations. The amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. TheCompany 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 standarddid not have a material impact on the Company's Consolidated Financial Statements. Refer to Note 11 – Employee Benefits for additional informationregarding the Company's pension and other postretirement plans.Note 2 – Acquisitions and Divestitures2017 Permian Basin AcquisitionIn 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, subjectto post-closing purchase price adjustments (the 2017 Permian Basin Acquisition). The 2017 Permian Basin Acquisition consists of approximately 15,100acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. QEP structured the transaction as a like-kind exchangeunder Section 1031 of the Internal Revenue Service Code and funded the purchase price with the proceeds from the Pinedale Divestiture. In accordance withthe early adoption of ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the definition of a business in the fourth quarter of 2017, the 2017Permian Basin Acquisition meets the definition of an asset acquisition because substantially all of the total fair value acquired relates to undevelopedleaseholds which do not have outputs. In addition, QEP has made offers to various persons who own additional oil and gas interests in certain propertiesincluded in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the original purchase. If all offers are accepted, theaggregate purchase price is not expected to exceed $50.0 million.2016 Permian Basin AcquisitionIn October 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $591.0 million (the 2016Permian Basin Acquisition). The 2016 Permian Basin Acquisition consists of approximately 9,600 net acres in Martin County, Texas, which are primarilyheld by production from existing vertical wells. The 2016 Permian Basin Acquisition was funded with cash on hand, which included proceeds from an equityoffering in June 2016.93The 2016 Permian Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included significantproved properties. QEP allocated the cost of the 2016 Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of theacquisition 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. Therevenue and net income (loss) are included in QEP's Consolidated Statements of Operations. During the year ended December 31, 2016, QEP incurredacquisition-related costs of $2.3 million, which are included in "General and administrative" expense on the Consolidated Statements of Operations. Inconjunction with the 2016 Permian Basin Acquisition, the Company recorded a $17.8 million bargain purchase gain. The acquisition resulted in a bargainpurchase 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 theacquisition. 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 $406.2Unproved properties 214.2Asset retirement obligations (11.6)Bargain purchase gain (17.8)Total fair value $591.0The following unaudited, pro forma results of operations are provided for the year ended December 31, 2016. Pro forma results are not provided for the yearended December 31, 2017, because the 2016 Permian Basin Acquisition occurred during the fourth quarter of 2016; and therefore, the results are included inQEP's results of operations for the year ended December 31, 2017. The supplemental pro forma results of operations are provided for illustrative purposesonly 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 beachieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because offuture events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the year endedDecember 31, 2016, the acquired properties' historical results of operations and estimates of the effect of the transaction on the combined results. The proforma results of operations have been prepared by adjusting, and quantifying, the historical results of QEP to include the historical results of the acquiredproperties based on information provided by the seller and the impact of the purchase price allocation. The pro forma results of operations do not include anycost 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 theCompany to integrate the acquired properties. Year ended December 31, 2016 Actual Pro forma (in millions, except per share amounts)Revenues $1,377.1 $1,392.5Net income (loss) $(1,245.0) $(1,246.8)Earnings (loss) per common share Basic $(5.62) $(5.62)Diluted $(5.62) $(5.62)94Other AcquisitionsIn addition to the 2017 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2017, which primarily included undeveloped leaseholdacreage, 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 anaggregate purchase price of $54.6 million, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leaseholdacreage. In conjunction with the acquisitions, the Company recorded $3.7 million of goodwill, which was subsequently impaired, and a $4.4 million bargainpurchase 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 purchaseprice of $98.3 million, which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage. Inconjunction with the acquisitions, the Company recorded $14.3 million of goodwill, which was subsequently impaired.Pinedale DivestitureIn September 2017, QEP sold its Pinedale assets (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million, subjectto 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 derivativecontracts covering a portion of Pinedale's future production. Those derivative contracts were novated to the buyer at closing. In addition, QEP agreed toreimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between theeffective 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 measuredutilizing an internally developed cash flow model discounted at QEP's weighted average cost of debt. Given the unobservable nature of the inputs, the fairvalue calculation associated with the deficiency charges is considered Level 3 within the fair value hierarchy. As of December 31, 2017, the liabilityassociated with estimated future payments for this commitment was $30.6 million, of which $27.4 million is reported on the Consolidated Balance Sheetswithin "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 theCompany and as a result, did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposalsof Components of an Entity. The Pinedale Divestiture did, however, represent the sale of an individually significant component. For the year endedDecember 31, 2017, QEP recorded net income before income taxes related to Pinedale, prior to the divestiture, of $251.0 million, which includes the pre-taxgain 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 beforeincome 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 gasprices. For the year ended December 31, 2015, QEP recorded net loss before income taxes of $45.6 million related to Pinedale.95Other DivestituresIn addition to the Pinedale Divestiture, during the year ended December 31, 2017, QEP also sold its Central Basin Platform assets (Central Basin PlatformDivestiture) and received net cash proceeds of $3.5 million. Refer to Note 3 – Capitalized Exploratory Well Costs for more information. In addition, QEPreceived 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 OtherNorthern 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 $31.7million, 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 endedDecember 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 CostsNet 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 $12.6Additions to capitalized exploratory well costs10.7 11.7 6.0Reclassifications to proved properties(3.6) — (16.0)Capitalized exploratory well costs charged to expense(21.3) (0.1) —Balance at December 31,$— $14.2 $2.6The balance at December 31, 2016 and 2015 represents the amount of capitalized exploratory well costs that are pending the determination of provedreserves.During the years ended December 31, 2017 and 2016, QEP's exploratory well activity was related to the Central Basin Platform exploration project in thePermian Basin targeting the Woodford Formation. QEP completed a second exploratory well related to this project in the first half of 2017. During the yearended December 31, 2017, based on the performance of the two exploratory wells that were drilled and the analysis of the ultimate economic feasibility ofthis exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project and would seek tomonetize the assets. QEP charged $21.3 million of exploratory well costs to exploration expense. In conjunction with the expensing of the exploratory wellcosts, QEP charged $28.3 million of the associated unproved leasehold acreage in the Central Basin Platform to impairment expense during the year endedDecember 31, 2017. QEP wrote down the Central Basin Platform assets to their fair market value of $3.6 million and reclassified the assets to provedproperties. 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 costsassociated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costsof similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or materialchanges 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.96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 $206.8Accretion7.7 8.9Additions(1)23.5 17.0Revisions8.5 6.5Liabilities 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 yearended December 31, 2016, include $11.6 million related to the 2016 Permian Basin Acquisition (refer to Note 2 – Acquisitions and Divestitures formore 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 fairvalue in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 also establishes afair value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability toaccess 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, eitherdirectly 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 thereporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements andmaximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assetsand liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, includingassumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers betweenlevels 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 quotedforward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevanteconomic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived fromobservable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivativeassets and liabilities also incorporates nonperformance risk for counterparties and for QEP. Derivative contract fair values are reported on a net basis to theextent a legal right of offset with the counterparty exists.97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 NettingAdjustments(1) Net AmountsPresented on theConsolidated BalanceSheets Level 1 Level 2 Level 3 (in millions) December 31, 2017Financial Assets Fair value of derivative contracts – short-term$— $20.6 $—$(17.2)$3.4Fair value of derivative contracts – long-term— 2.3 —(2.2)0.1Total financial assets$— $22.9 $— $(19.4) $3.5 Financial Liabilities Fair value of derivative contracts – short-term$— $120.8 $— $(17.2)$103.6Fair value of derivative contracts – long-term— 34.0 — (2.2) 31.8Total financial liabilities$— $154.8 $— $(19.4) $135.4 December 31, 2016Financial Assets Fair value of derivative contracts – short-term$— $— $— $— $—Fair value of derivative contracts – long-term— — — — —Total financial assets$—$—$—$—$— Financial Liabilities Fair value of derivative contracts – short-term$— $169.8 $— $— $169.8Fair value of derivative contracts – long-term— 32.0 — — 32.0Total financial liabilities$—$201.8$—$—$201.8 ____________________________(1) The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Consolidated Balance Sheets for thecontracts that contain netting provisions. Refer to Note 6 – Derivative Contracts for additional information regarding the Company's derivativecontracts.The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes to the ConsolidatedFinancial Statements in this Annual Report on Form 10-K: Carrying Amount Level 1 FairValue Carrying Amount Level 1 FairValue December 31, 2017 December 31, 2016Financial Assets(in millions)Cash and cash equivalents$— $— $443.8 $443.8Financial Liabilities Checks outstanding in excess of cash balances$44.0 $44.0 $12.3 $12.3Long-term debt$2,160.8 $2,256.2 $2,020.9 $2,104.398The carrying amounts of cash and cash equivalents and checks outstanding in excess of cash balances approximate fair value. The fair value of fixed-ratelong-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-termdebt 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 costsassociated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO include plugging costs and reserve lives. Areconciliation of the Company's ARO is presented in Note 4 – Asset Retirement Obligations.Nonrecurring Fair Value MeasurementsThe provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on anonrecurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in therecoverability of the carrying value of such property. During the years ended December 31, 2017 and 2016, the Company recorded impairments of certainproved 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. Thefair value of the property was measured utilizing the income approach and utilizing inputs which are primarily based upon internally developed cash flowmodels discounted at an appropriate weighted average cost of capital. Given the unobservable nature of the inputs, fair value calculations associated withproved oil and gas property impairments are considered Level 3 within the fair value hierarchy. Refer to Note 1 – Summary of Significant AccountingPolicies 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 modelto estimate the fair value of acquired property as of the acquisition date which utilizes the following inputs to estimate future net cash flows: (i) estimatedquantities of oil, gas and NGL reserves; (ii) estimates of future commodity prices; and (iii) estimated production rates, future operating and developmentcosts, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactionsis used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the acquired properties is consideredLevel 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 ContractsQEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course ofbusiness, 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 ofproduction subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response tochanging market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production, but generally, QEP enters intocommodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. Inaddition, QEP may enter into commodity derivative contracts on a portion of its storage transactions. QEP does not enter into commodity derivative contractsfor 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 ofproduction delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between theparties 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, forthe settlement period. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma or oil price swapsthat use ICE Brent oil prices as the reference price. Gas price derivative instruments are typically structured as fixed-price swaps or costless collars at NYMEXHenry 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 pricesthat 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 priorto the scheduled settlement dates. QEP's commodity derivative contract counterparties are typically financial institutions and energy trading firms withinvestment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for allcounterparties, actively monitoring counterparties public credit ratings and avoiding the concentration of credit exposure by transacting with multiplecounterparties. The Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a defaultsituation. Derivative Contracts – ProductionThe 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 perUnit (in millions) Oil sales (bbls) ($/bbl)2018 NYMEX WTI 16.8 $52.482019 NYMEX WTI 8.0 $51.78Gas sales (MMBtu) ($/MMBtu)2018 (Full Year) NYMEX HH 109.5 $2.992018 (July through December) NYMEX HH 1.8 $3.012019 NYMEX HH 36.5 $2.88QEP uses oil and gas basis swaps, combined with NYMEX WTI and NYMEX HH fixed price swaps, to achieve fixed price swaps for the location at which itsells its physical production. The following table presents details of QEP's oil and gas basis swaps as of December 31, 2017:Year Index Less Differential Index Total Volumes Weighted-AverageDifferential (in millions) Oil sales (bbls) ($/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 $(0.16)Derivative Contracts – Gas StorageQEP enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage. The following table presents QEP's volumes andaverage prices for its gas storage commodity derivative swap contracts as of December 31, 2017:Year Type of Contract Index Total Volumes Average Swap Price per Unit (in millions) Gas sales (MMBtu) ($/MMBtu)2018 SWAP IFNPCR 0.6 $3.06100QEP Derivative Financial Statement PresentationThe following table identifies the Consolidated Balance Sheets location of QEP's outstanding derivative contracts on a gross contract basis as opposed to thenet contract basis presentation on the Consolidated Balance Sheets and the related fair values at the balance sheet dates: Gross asset derivativeinstruments fair value Gross liability derivativeinstruments fair value December 31, Balance Sheet line item 2017 2016 2017 2016Current: (in millions)CommodityFair value of derivative contracts $20.6 $— $120.8 $169.8Long-term: CommodityFair value of derivative contracts 2.3 — 34.0 32.0Total derivative instruments $22.9 $— $154.8 $201.8101The effects of the change in fair value and settlement of QEP's derivative contracts recorded in "Realized and unrealized gains (losses) on derivativecontracts" 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 2015Realized gains (losses) on commodity derivative contracts (in millions)Production Oil derivative contracts $6.8 $86.3 $353.7Gas derivative contracts (22.3) 44.8 103.4Gas Storage Gas derivative contracts — 2.9 3.8Realized gains (losses) on commodity derivative contracts (15.5) 134.0 460.9Unrealized gains (losses) on commodity derivative contracts Production Oil derivative contracts (66.2) (217.2) (244.9)Gas derivative contracts 133.6 (145.4) 62.0Gas 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 toproduction 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 PinedaleDivestiture $(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 inconjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of thesale in September 2017. Refer to Note 2 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodityderivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales" on theConsolidated Statements of Operations.Note 7 – Restructuring CostsIn April 2016, the Company streamlined its organizational structure, resulting in a reduction of approximately 6% of its total workforce. The total costsrelated 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 the2016 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 costsrelated to the 2015 restructuring events were approximately $8.3 million, of which approximately $5.3 million was related to one-time termination benefitsand approximately $3.0 million was related to relocation of certain employees. During the year ended December 31, 2016, restructuring costs of $0.6 millionwere incurred and paid related to the Tulsa office closure, all of which were related to the relocation of certain employees. The Company did not incuradditional 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 – DebtAs 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)— 134.06.80% Senior Notes due 2020(1)51.7 136.06.875% Senior Notes due 2021(1)397.6 625.05.375% Senior Notes due 2022500.0 500.05.25% Senior Notes due 2023650.0 650.05.625% 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 themajority 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 millionof 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 millionloss 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 the5.375% 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 FacilityIn November 2017, QEP entered into the Seventh Amendment to its Credit Agreement, which, among other things, reduced the aggregate principal amount ofcommitments to $1.25 billion and extended the maturity date, subject to satisfaction of certain conditions, to September 1, 2022. The credit facility providesfor 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 thecredit 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 notexceed 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarter ending December 31, 2017, 4.00 times commencing withthe fiscal quarter ending March 31, 2018, through the fiscal quarter ending December 31, 2018, and 3.75 times thereafter, and (iii) during a ratings triggerperiod (as defined), a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.25times 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, andmust 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, QEPhad no borrowings outstanding and $2.8 million in letters of credit outstanding under the credit facility.Senior NotesAt December 31, 2017, the Company had $2,099.3 million principal amount of senior notes outstanding with maturities ranging from March 2020 to March2026 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 ofour 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 aredemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP's senior notescontain 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 ContingenciesThe 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 accrualin its Consolidated Financial Statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when itsoccurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range ofpossible outcomes.Legal proceedings are inherently unpredictable and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires judgmentabout uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a numberof factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoingdiscovery and/or development of information important to the matter.LitigationLandowner 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 judgmentthat 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. TheCompany is unable to make an estimate of the reasonably possible loss at this early stage.CommitmentsQEP has contracted for gathering, processing, firm transportation and storage services with various third parties. Market conditions, drilling activity andcompetition may prevent full utilization of the contractual capacity. In addition, QEP has contracts with third parties who provide drilling services. Annualpayments and the corresponding years for gathering, processing, transportation, storage, drilling, and fractionation contracts are as follows (in millions):YearAmount2018$95.62019$68.42020$54.92021$29.92022$28.3After 2022$122.5104QEP rents office space throughout its scope of operations from third-party lessors. Rental expense from operating leases amounted to $9.6 million, $9.1million, and $8.0 million during the years ended December 31, 2017, 2016 and 2015, respectively. Minimum future payments under the terms of long-termoperating leases for the Company's primary office locations are as follows (in millions):YearAmount2018$7.02019$7.22020$7.42021$7.42022$7.2After 2022$4.8Note 10 – Share-Based CompensationQEP issues stock options, restricted share awards and restricted share units under its LTSIP and awards performance share units under its CIP to certainofficers, employees, and non-employee directors. QEP recognizes expense over the vesting periods for the stock options, restricted share awards, restrictedshare 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 ConsolidatedStatements of Operations and is summarized in the table below. Year Ended December 31, 2017 2016 2015 (in millions)Stock options$2.3 $2.3 $2.9Restricted share awards24.6 23.7 25.6Performance share units(4.5) 9.4 6.2Restricted share units— 0.2 —Total share-based compensation expense$22.4 $35.6 $34.7Stock OptionsQEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of grant. Fair value calculations relyupon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intendedfor calculating the value of options not traded on an exchange. The Company utilizes the "simplified" method to estimate the expected term of the stockoptions granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatilitymethod 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 tothose 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 areexercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock orissues 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 2015Weighted-average grant date fair value of awards granted during the period$6.44 $3.77 $6.82Risk-free interest rate range1.66% - 1.81% 0.99% - 1.15% 1.38% - 1.38%Weighted-average risk-free interest rate1.8% 1.2% 1.4%Expected price volatility range43.82% - 46.70% 43.42% - 43.66% 36.8% - 36.8%Weighted-average expected price volatility43.9% 43.4% 36.8%Expected dividend yield—% —% 0.37%Expected term in years at the date of grant4.5 4.5 4.5Stock option transactions under the terms of the LTSIP are summarized below: OptionsOutstanding Weighted-AverageExercise Price Weighted-AverageRemainingContractual Term Aggregate IntrinsicValue (per share) (in years) (in millions)Outstanding at December 31, 20162,151,957 $25.26 Granted418,752 16.77 Forfeited(14,172) 15.33 Cancelled(202,260) 27.55 Outstanding at December 31, 20172,354,277 $23.62 3.50 $—Options Exercisable at December 31, 20171,551,861 $27.90 2.47 $—Unvested Options at December 31, 2017802,416 $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 marketprice 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 taximpact 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 $6.4million of income tax expense for the year ended December 31, 2015. As of December 31, 2017, $1.6 million of unrecognized compensation cost related tostock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.04 years.Restricted Share AwardsRestricted share award grants typically vest in equal installments over a three-year period from the grant date. The grant date fair value is determined basedon 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. Thetotal 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 $22.7million, respectively. There was no income tax impact for the year ended December 31, 2017 and 2016. The Company realized an income tax benefit of $3.2million 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 pershare 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 unrecognizedcompensation cost related to restricted share awards granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 1.99years.106Transactions involving restricted share awards under the terms of the LTSIP are summarized below: Restricted Share AwardsOutstanding Weighted-Average GrantDate Fair Value (per share)Unvested balance at December 31, 20163,208,503 $14.32Granted2,219,763 13.90Vested(1,392,043) 16.53Forfeited(314,889) 14.49Unvested balance at December 31, 20173,721,334 $13.23Performance Share UnitsThe 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 tosettle 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 allawards in cash. These awards are classified as liabilities and are included within "Other long-term liabilities" on the Consolidated Balance Sheets. As theseawards 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. TheCompany 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 theunvested 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 UnitsOutstanding Weighted-Average GrantDate Fair Value (per share)Unvested balance at December 31, 20161,027,280 $17.24Granted405,014 16.90Vested and paid(215,439) 31.63Forfeited(17,519) 13.88Unvested balance at December 31, 20171,199,336 $14.59Restricted Share UnitsEmployees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share unitsvest over a three-year period and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. These awards areultimately delivered in cash. They are classified as liabilities in "Other long-term liabilities" on the Consolidated Balance Sheets and are measured at fairvalue 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 theyears ended December 31, 2017 and 2016, respectively. As of December 31, 2017, $0.1 million of unrecognized compensation cost, which represents theunvested 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 UnitsOutstanding Weighted-Average GrantDate Fair Value (per share)Unvested balance at December 31, 201618,034 $10.12Granted9,924 16.98Vested(6,012) 10.12Unvested balance at December 31, 201721,946 $13.22Note 11 – Employee BenefitsPension and other postretirement benefitsThe 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 ofDecember 31, 2017, covers 30 active and suspended participants, or 5%, of QEP's active employees, and 184 participants that are retired or were terminatedand 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 ofemployment or December 31, 2015, and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding termination ofemployment or, if earlier, December 31, 2015. During the year ended December 31, 2017, the Company made contributions of $4.0 million to the PensionPlan and expects to contribute approximately $4.0 million to the Pension Plan in 2018. Contributions to the Pension Plan increase plan assets. Due to thePension Plan freeze on January 1, 2016, the Company began making additional contributions for eligible employees who were active participants in thePension Plan on December 31, 2015 based on the eligible employee's age as of December 31, 2015. During the year ended December 31, 2017, QEPcontributed $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 theyear ended December 31, 2015, which is the minimum number of active participants for a plan to meet the qualification requirements of the minimumparticipation rules under the Internal Revenue Code. In order to prevent disqualification, the Pension Plan was amended in June 2015 and was frozeneffective January 1, 2016, such that employees do not earn additional defined benefits for future services except for purposes of determining eligibility for anearly retirement benefit. This change resulted in a non-cash curtailment loss of $11.2 million recognized on the Consolidated Statements of Operationswithin "Interest and other income (expense)" expense during the year ended December 31, 2015. A curtailment is recognized immediately when there is asignificant 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 theemployee's age at retirement, years of service and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding theparticipant's termination of employment. During the year ended December 31, 2017, the Company made contributions of $2.0 million to its SERP andexpects to contribute approximately $0.7 million in 2018. Contributions to the SERP are used to fund current benefit payments. The SERP was amended andrestated 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 PinedaleDivestiture, 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 forcertain retired QEP employees. The Medical Plan was originally provided only to employees hired by Questar Corporation before January 1, 1997. Of the 30active, pension eligible employees, 17 are also eligible for the Medical Plan when they retire. As of December 31, 2017, 55 retirees are enrolled in theMedical 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 receivethe maximum company contribution. During the year ended December 31, 2017, the Company made contributions of $0.1 million and expects to contributeapproximately $0.3 million of benefits in 2018. At December 31, 2017 and 2016, QEP's accumulated benefit obligation exceeded the fair value of itsqualified 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 nolonger 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 periodicpension cost and net periodic postretirement benefit cost, the Company recast years ended December 31, 2016 and 2015 by recognizing service costsrelated to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of Operations. All other expensesrelated to the Pension Plan, SERP and Medical Plan are recognized within "Interest and other income (expense)" on the Consolidated Statements ofOperations.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 theyears 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, 2017and 2016: Pension Plan and SERP benefits Medical Plan benefits 2017 2016 2017 2016Change in benefit obligation(in millions)Benefit obligation at January 1,$129.2 $120.3 $5.4 $5.2Service cost0.8 1.2 — —Interest cost4.7 5.2 0.1 0.2Curtailments(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) 0.4Benefit obligation at December 31,$130.0 $129.2 $2.9 $5.4Change in plan assets Fair value of plan assets at January 1,$86.1 $79.3 $— $—Actual return on plan assets15.3 7.4 — —Company contributions to the plan6.0 7.2 0.1 0.4Benefit payments(6.9) (7.8) (0.1) (0.4)Fair value of plan assets at December 31,100.5 86.1 — —Underfunded status (current and long-term)$(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 cost1.2 2.9 (1.2) 1.0Total amount recognized in AOCI$16.2 $26.4 $(1.7) $0.6110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 2015Components of net periodic benefit cost(in millions)Service cost$0.8 $1.2 $2.1 $— $— $—Interest cost4.7 5.2 4.9 0.1 0.2 0.2Expected return on plan assets(5.4) (5.6) (5.7) — — —Curtailment loss0.7 — 11.2 — — —Settlements0.2 — — — — —Amortization of prior service costs1.0 1.1 1.7 (0.3) 0.2 0.2Amortization of actuarial loss0.5 0.8 0.5 (0.1) — —Periodic expense$2.5 $2.7 $14.7$(0.3) $0.4 $0.4Components recognized in accumulated other comprehensiveincome Current period prior service cost$(0.7) $— $0.9 $(2.5) $— $—Current period actuarial (gain) loss(7.5) 8.5 2.2 (0.1) 0.4 (1.4)Amortization of prior service cost(1.0) (1.1) (12.9) 0.3 (0.2) (0.2)Amortization of actuarial gain (loss)(0.5) (0.8) (0.5) 0.1 — —Loss on curtailment in current period(0.3) — (7.1) — — —Settlements(0.2) — — — — —Total amount recognized in accumulated othercomprehensive income$(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 andadministrative" expense. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized on the Consolidated Statements ofOperations 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 benefitcost in 2018 is $1.9 million, which represents amortization of prior service cost recognized and actuarial losses. The estimated portion of net actuarial lossand 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 representsamortization of prior service cost recognized and actuarial gains. Amortization of prior service costs and actuarial gains or losses out of AOCI are recognizedin 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 thePension Plan, SERP and Medical Plan obligations at December 31, 2017 and 2016: Pension Plan and SERP benefits Medical Plan benefits 2017 2016 2017 2016Discount rate3.52% 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 consideredan 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 rateof 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 obligationscould 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 netperiodic 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 2015Discount rate4.00% 4.23% 3.94% 4.10% 4.40% 4.00%Expected long-term return on plan assets6.00% 6.50% 6.75% n/a n/a n/aRate 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 consideredan 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 rateof 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 beinvested to provide benefits. This includes considering the plan's asset allocation, historical returns on these types of assets, the current economicenvironment 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 theCompany'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 AssetsThe Company's Employee Benefits Committee (EBC) oversees investment of qualified pension plan assets. The EBC uses a third-party asset manager toassist in setting targeted-policy ranges for the allocation of assets among various investment categories. The EBC allocates pension plan assets among broadasset categories and reviews the asset allocation at least annually. Asset allocation decisions consider risk and return, future-benefit requirements, participantgrowth 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. Theseguidelines 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 aredeveloped from analysis of past performance and forecasts of long-term return expectations by third-parties. Responsibility for individual security selectionrests with each investment manager, who is subject to guidelines specified by the EBC. The EBC sets performance objectives for each investment managerthat 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 toconfirm policy compliance and that results are within expectations. Performance for each investment is measured relative to the appropriate index benchmarkfor its category. QEP securities may be considered for purchase at an investment manager's discretion, but within limitations prescribed by the EmployeeRetirement Income Security Act of 1974 (ERISA) and other laws. There was no direct investment in QEP shares for the periods disclosed. The majority ofretirement-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 goalrepresentative of the whole U.S. stock market. International equity securities consisted of developed and emerging market foreign equity assets that wereinvested 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 andmortgage borrowers with average maturities of five to ten years and investment grade credit ratings. Investment grade long-term debt assets are invested in adiversified portfolio of debt of corporate and non-corporate issuers, with an average maturity of more than ten years and investment grade credit ratings. Highyield 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 deemednecessary 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 moretax efficient than mutual funds. These investments are public investment vehicles valued using the net asset value (NAV) as a practical expedient. The NAVis 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. Thesecommingled 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 NetAsset 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 ASC820, Fair Value Measurements and Disclosures, as all investments are measured at NAV as a practical expedient, which are now required to be excluded fromthe 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: Domestic35.0 35% 39.3 46%International15.3 15% 21.6 25%Fixed income49.7 50% 21.7 25%Total investments$100.5 100% $86.1 100%Expected Benefit PaymentsAs of December 31, 2017, the following future benefit payments are expected to be paid: Pension Plan and SERPbenefits Medical Plan benefits (in millions)2018$6.6 $0.22019$8.1 $0.22020$7.6 $0.22021$8.3 $0.22022$6.8 $0.22023 through 2026$39.1 $0.6113Employee Investment PlanQEP employees may participate in the QEP Employee Investment Plan, a defined-contribution plan (the 401(k) Plan). The 401(k) Plan allows eligibleemployees to make investments, including purchasing shares of QEP common stock, through payroll deduction at the current fair market value on thetransaction date. Participants receive 100% employer matching contributions on participant 401(k) plan contributions up to a percentage of qualifyingearnings as described below. Year Ended December 31, 2017 2016 2015Employees not covered by the Pension Plan or SERP(1) Maximum employer matching of qualifying earnings8% 8% 8% Employees covered by the Pension Plan but not the SERP(1) Maximum employer matching of qualifying earnings8% 8% 6% Employees covered by both the Pension Plan and the SERP(1) Maximum employer matching of qualifying earnings6% 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. TheCompany recognizes expense equal to its yearly contributions, which amounted to $6.0 million, $5.6 million and $6.3 million during the years endedDecember 31, 2017, 2016 and 2015, respectively.Note 12 – Income TaxesOn 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 incometax 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 rateof 21% compared to 35%. The Tax Legislation also repeals the corporate alternative minimum tax (AMT). Several provisions of the new tax law such aslimitations on the deductibility of interest expense and certain executive compensation and the inability to use Section 1031 like-kind exchanges for assetssuch as machinery and equipment could apply to QEP; however, we do not believe that they will materially impact QEP's financial statements. The impact ofthe Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made andactions the Company may take as a result of the Tax Legislation. Additionally, guidance issued by the relevant regulatory authorities regarding the TaxLegislation may materially impact QEP's financial statements. The Company will continue to analyze the Tax Legislation to determine the full impact of thenew 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 2015Federal income tax provision (benefit)(in millions)Current$2.1 $(55.5) $(112.3)Deferred(339.8) (614.3) 34.5State income tax provision (benefit) Current0.5 (1.5) (6.6)Deferred25.0 (36.9) (9.2)Total income tax provision (benefit)$(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 2015Federal income taxes statutory rate35.0 % 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 change2.1 % (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 rate727.7 % 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 torevalue its deferred tax liabilities and assets as of December 31, 2017 from a 35% to 21% federal corporate income tax rate which caused themajority of the change in rate.Significant components of the Company's deferred income taxes were as follows: December 31, 2017(1) 2016Deferred tax liabilities(in millions)Property, plant and equipment$898.7 $1,135.0Deferred tax assets Net operating loss and tax credit carryforwards$308.8 $161.6Employee benefits and compensation costs26.4 49.0Bonus and vacation accrual6.2 11.4Commodity price derivatives29.9 74.3Other9.4 12.8Total deferred tax assets380.7 309.1Net deferred income tax liability$518.0$825.9Balance sheet classification Deferred income tax liability – noncurrent518.0 825.9Net 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 thefederal 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 carryforwards2018-2037 $95.8State net operating loss valuation allowance $(56.8)U.S. net operating loss2036-2037 $250.4U.S. alternative minimum tax creditIndefinite $19.5The valuation allowance of $56.8 million was established in 2014 and 2017 against the available state net operating loss and is related primarily to lossesincurred 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 itsproperties in Oklahoma, the Company does not forecast sufficient taxable income to utilize the net operating loss in Oklahoma. In 2017, a valuationallowance of $31.8 million was established against Louisiana's net operating loss as the Company does not forecast sufficient taxable income to utilize theentire 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 AMTcredits carried forward from prior years. The Company currently anticipates it will realize approximately $19.5 million in AMT value over the next four yearswith approximately half of this value estimated to be realized in 2019 for taxable year 2018.Unrecognized Tax BenefitAs of December 31, 2017 and 2016, QEP had $19.0 million and $15.6 million, respectively, of unrecognized tax benefits related to uncertain tax positionsfor asset sales that occurred in 2014, which were recorded within "Other long-term liabilities" on the Consolidated Balance Sheets. The $15.6 millionuncertain tax position the Company reported during the year ended December 31, 2016, was expensed during the year ended December 31, 2014, with anadditional $3.4 million expensed during the year ended December 31, 2017 with the new Tax Legislation. The benefits of uncertain tax positions taken orexpected 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 besustained upon examination by the relevant taxing authorities. Our policy is to recognize any interest expense related to uncertain tax positions in "Interestexpense" 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 interestexpense 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 $15.6Federal benefit of state (change from 35% to 21%)3.4 —Balance as of December 31,$19.0 $15.6As of December 31, 2017 and 2016, QEP had approximately $19.0 million and $15.6 million, respectively, of unrecognized tax benefit that would impact itseffective 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 thestate 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 Year2017(in millions, except per share amounts or otherwise specified)Revenues$420.1 $383.7 $390.1 $429.0 $1,622.9Operating income (loss)(5.2) (0.9) 132.1 (24.5) 101.5Net income (loss)76.9 45.4 (3.3) 150.3 269.3Net gain (loss) from asset sales and impairment(0.1) 19.8 157.1 (42.2) 134.6Nonrecurring items in operating income (loss)(1)— — 8.2 — 8.2Per share information Basic EPS$0.32 $0.19 $(0.01) $0.62 $1.12Diluted EPS0.32 0.19 (0.01) 0.62 1.12Production information Total equivalent production (Mboe)13,090.3 13,860.6 14,124.1 12,069.9 53,144.9Total equivalent production (Bcfe)78.6 83.2 84.7 72.1 318.62016 Revenues$261.3 $333.7 $382.4 $399.7 $1,377.1Operating income (loss)(1,379.0) (92.1) (93.1) (36.5) (1,600.7)Net income (loss)(863.8) (197.0) (50.9) (133.3) (1,245.0)Net gain (loss) from asset sales and impairment(1,181.9) (1.6) 0.3 (6.1) (1,189.3)Nonrecurring items in operating income (loss)(1)7.7 — 25.0 — 32.7Per share information Basic EPS$(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 55,780.2Total 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 – Oiland Gas, as amended by ASU 2010-03, Oil and Gas Reserve Estimation and Disclosures, and SEC Regulation S-X. The Company uses the successful effortsaccounting method for its oil and gas exploration and development activities. All of QEP's properties are located in the United States.117Capitalized CostsThe 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 $14,232.5Unproved properties, net1,095.8 871.5Total proved and unproved properties13,566.7 15,104.0Accumulated depreciation, depletion and amortization(6,642.9) (8,797.7)Net capitalized costs$6,923.8 $6,306.3Costs IncurredThe costs incurred in oil and gas acquisition, exploration and development activities are displayed in the table below. Development costs are net of thechange 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 costsincurred 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 $49.6Unproved property acquisitions532.4 208.7 39.8Other acquisitions13.2 — —Exploration costs (capitalized and expensed)32.7 13.4 8.7Development costs1,189.3 509.2 1,010.3Total costs incurred$2,037.2 $1,162.9 $1,108.4Results of OperationsFollowing 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 $1,390.4Production costs675.4 616.7 654.1Exploration expenses22.0 1.7 2.7Depreciation, depletion and amortization735.1 852.3 870.8Impairment72.3 1,194.3 55.6Total expenses1,504.8 2,665.0 1,583.2Income (loss) before income taxes43.3 (1,394.0) (192.8)Income tax benefit (expense)(16.0) 517.2 70.6Results of operations from producing activities excluding allocatedcorporate overhead and interest expenses$27.3 $(876.8) $(122.2)118Estimated Quantities of Proved Oil and Gas ReservesEstimates of proved oil and gas reserves have been completed in accordance with professional engineering standards and the Company's established internalcontrols, which includes the oversight of a multi-functional Reserves Review Committee reporting to the Company's Audit Committee of the Board ofDirectors. The Company retained Ryder Scott Company, L.P. (RSC), independent oil and gas reserve evaluation engineering consultants, to prepare theestimates 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 ofits 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 asamended. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation andevaluation. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results ofadditional 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 initiallydisclosed as proved undeveloped reserves. The Company plans to continue development of its leaseholds and anticipates that it will have the financialcapability 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'schange 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 96.6 655.3Revisions of previous estimates(1) (47.0) (463.8) (55.3) (179.6)Extensions and discoveries(2) 85.6 467.7 21.8 185.4Purchase of reserves in place(3) 2.0 3.2 0.6 3.1Sale 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 58.8 603.4Revisions of previous estimates(5) (9.7) 412.8 (0.3) 58.8Extensions and discoveries(6) 13.0 158.1 3.3 42.6Purchase of reserves in place(7) 62.7 54.6 11.5 83.3Sale 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 67.2 731.4Revisions of previous estimates(9) 3.7 12.5 (3.1) 2.7Extensions and discoveries(10) 59.1 101.9 10.4 86.4Purchase of reserves in place(11) 46.6 125.5 8.7 76.3Sale 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 1,793.665.2684.7Proved developed reserves Balance at December 31, 2014 99.3 1,288.4 52.2 366.2Balance at December 31, 2015 109.7 1,245.3 34.4 351.6Balance at December 31, 2016 103.2 1,309.8 35.7 357.2Balance at December 31, 2017 116.0 655.5 27.9 253.1Proved undeveloped reserves Balance at December 31, 2014 73.2 1,028.8 44.4 289.1Balance at December 31, 2015 83.4 863.6 24.4 251.8Balance at December 31, 2016 135.4 1,244.0 31.5 374.2Balance 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 revisionsunrelated to pricing, partially offset by 13.7 MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas andNGL 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 WillistonBasin 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 tonew 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 asdiscussed 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 andDivestitures.120(5) Revisions of previous estimates in 2016 include 77.3 MMboe of positive revisions, primarily related to successful workovers in Haynesville/CottonValley; reserves associated with increased density wells in areas that have been previously developed on lower density spacing; and 5.5 MMboe ofpositive performance revisions. These positive revisions were partially offset by 18.5 MMboe of negative revisions related to pricing, driven bylower 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 PUDlocations.(7) Purchase of reserves in place in 2016 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions andDivestitures.(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 andDivestitures.(9) Revisions of previous estimates in 2017 include 2.7 MMboe of positive revisions, primarily related to 32.0 MMboe of positive revisions related topricing, driven by higher oil, gas and NGL prices and 2.2 MMboe of positive performance revisions. These positive revisions were partially offset by11.0 MMboe of negative revisions related to higher operating costs and 20.5 MMboe of other revisions primarily from changing to a horizontaldevelopment plan from a vertical well development plan in the Uinta Basin and increased longer laterals in Haynesville/Cotton Valley. Thesenegative other revisions are partially offset by positive other revisions from successful infill drilling in Haynesville/Cotton Valley and the WillistonBasin.(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 gasproperties 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 inreserves when the volumes replaced fuel purchases.Standardized Measure of Discounted Future Net Cash Flows Relating to Proved ReservesFuture 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-monthcommodity prices, adjusted for location and quality differentials, for each of the 12 months during 2017, 2016 and 2015, with consideration of knowncontractual price changes. The prices used do not include any impact of QEP's commodity derivatives portfolio. The following table provides the averagebenchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category: For the year ended December 31, 2017 2016 2015Average benchmark price per unit: Oil price (per bbl)$51.34 $42.75 $50.28Gas price (per MMBtu)$2.98 $2.48 $2.59Year ended operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to computethe 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. Theestimated future costs to develop proved undeveloped reserves are approximately $486.5 million in 2018, $710.0 million in 2019 and $1,006.2 million in2020. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. QEPbelieves cash flow from its operating activities, cash on hand and borrowings under its revolving credit facility will be sufficient to cover these estimatedfuture 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 2018.121The assumptions used to derive the standardized measure of discounted future net cash flows are those required by accounting standards and do notnecessarily reflect the Company's expectations. The information may be useful for certain comparative purposes but should not be solely relied upon inevaluating QEP or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, norshould the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company's reserves. Managementbelieves 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 productionrates 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 therisk 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 $15,325.3Future 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 flows6,789.6 4,104.5 4,563.610% 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 theTax Legislation enacted in December 2017.122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 $5,340.0Sales 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 production1,457.2 (739.4) (6,307.8)Net change due to extensions and discoveries556.8 81.8 1,765.7Net change due to revisions of quantity estimates9.9 122.7 (1,350.2)Net change due to purchases of reserves in place342.7 256.5 29.7Net change due to sales of reserves in place(504.7) (4.3) (48.8)Previously estimated development costs incurred during the period475.4 374.6 865.0Changes in estimated future development costs(283.4) (476.5) 560.7Accretion of discount235.7 311.1 752.9Net change in income taxes(227.4) 205.4 1,554.4Other(20.2) (25.9) 51.0Net change1,169.3 (548.3) (2,863.7)Balance at December 31,$3,097.3 $1,928.0 $2,476.3Note 15 – Subsequent EventIn February 2018, in conjunction with the 2017 Permian Basin Acquisition, QEP entered into agreements to acquire oil and gas properties in the PermianBasin for an aggregate purchase price of $36.1 million, subject to customary purchase price adjustments. The transactions are expected to be funded withborrowings 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 administrativeexpenses 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 disclosurecontrols 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 ofDecember 31, 2017. Based on such evaluation, such officers have concluded that, as of December 31, 2017, the Company's disclosure controls andprocedures are designed and effective to ensure that information required to be included in the Company's reports filed or submitted under the Exchange Actis recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information required to be disclosedin the Company's reports filed or submitted under the Exchange Act is accumulated and communicated to the Company's management including its principalexecutive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding requireddisclosure. 123In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and procedures, no matter how welldesigned and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the designof 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 assurancethat 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) thatoccurred during the quarter ended December 31, 2017, that have materially affected, or are reasonably likely to materially affect, the Company's internalcontrol 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 ActRules 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 executiveofficer and chief financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financialstatements for external purposes in accordance with accounting principles generally accepted. Because of its inherent limitations, internal control overfinancial reporting may not detect or prevent misstatements. Also, projections of any evaluation of the effectiveness to future periods are subject to the riskthat 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 InternalControl – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission for effective internal controlover financial reporting. Based on the assessment, management determined that the Company maintained effective internal control over financial reportingas 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 AnnualReport on Form 10-K, has issued an attestation report on the effectiveness of internal control over financial reporting as of December 31, 2017, which isincluded in the Consolidated Financial Statements in Item 8 of Part II of this Annual Report on Form 10-K.ITEM 9B. OTHER INFORMATIONApproval of Executive Retention and Severance Compensation ProgramOn February 26, 2018, QEP's Board of Directors approved an executive severance compensation program, pursuant to which each of QEP's named executiveofficers have entered into an Executive Severance Compensation Program letter agreement (the Severance Letters). The Severance Letters provide that in theevent the executive's employment with QEP is terminated without cause or the executive resigns his employment for good reason (as such terms are definedin the Severance Letters), and such termination or resignation occurs prior to September 30, 2020, the executive will be entitled to receive the followingseverance 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 salaryand 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, whichshall 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 onand 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 covereddependents' 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, acash payment representing two additional years of service credit under such plans.124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 theSeverance 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 namedexecutive officers (other than Mr. Stanley and Mr. Doleshek) have entered into an Executive Retention Bonus letter agreement (the Retention Letters). TheRetention 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 byQEP 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 theretention 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 fullletter agreements, which are attached as Exhibits 10.29 and 10.30, respectively to this Form 10-K and are incorporated herein by reference.Letter AgreementOn 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 whichwas 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 toimmediately declassify the existing board structure and provide for the annual election of directors (the Declassification Amendment). The Company hasagreed to recommend to its shareholders that they vote in favor of the Declassification Amendment. In connection with the Declassification Amendment, allof 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 AnnualMeeting, to be effective on such date. Should the Declassification Amendment be approved by the Company's shareholders, all of the directors shall serveuntil the 2019 annual meeting, including Mr. Thacker whose remaining term will expire at the 2019 annual meeting. If the Declassification Amendment isnot 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 theirresignation.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 certainof 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 therecommendations 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 timeperiod established pursuant to the Company's bylaws for shareholders to deliver notice to the Company of director nominations to be brought before the2019 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 proxyrules 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 StatesSecurities Exchange Act of 1934 (the Exchange Act), other than solely with affiliates of Elliott with respect to voting securities now or hereafter held bythem, (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 withrespect 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 extraordinarytransaction involving the Company, (e) enter into any voting trust or similar arrangement, (f) seek to (i) elect or appoint to, or have representation on, theBoard 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 orotherwise) 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 ofthe Agreement is qualified in its entirety by reference to the full text of the Agreement.125126PART IIIITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCEThe information required by Item 10 concerning QEP's directors and nominees for directors and other corporate governance matters will be presented in theCompany's definitive Proxy Statement prepared for the solicitation of proxies in connection with the Company's Annual Meeting of Stockholders, which theCompany expects to file with the Securities and Exchange Commission no later than 120 days subsequent to December 31, 2017 (Proxy Statement), and isincorporated 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) andemployees. QEP has posted the Code of Conduct on its website, www.qepres.com. Any waiver of the Code of Conduct for executive officers must beapproved 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 executiveofficers.ITEM 11. EXECUTIVE COMPENSATIONThe 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 MATTERSThe 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 INDEPENDENCEThe 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 SERVICESThe 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 Statementsand 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'sCurrent 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 QuarterlyReport 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 BankOne, NA, (predecessor-in-interest to Wells Fargo Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.01 to theCompany'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 Securitiesand 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 toExhibit 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 Exhibit4.1 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 byreference 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 Exhibit4.2 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 Exhibit4.1 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 referenceto 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 theadministrative agent, letter of credit issuer and swing line lender, and the lenders party thereto (incorporated by reference to Exhibit 10.1to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 29, 2011), as amended bythe 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 ExchangeCommission on August 16, 2013), the Third Amendment to Credit Agreement, dated as of January 31, 2014 (incorporated by reference toExhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on May 7, 2014), theFourth Amendment to Credit Agreement and Commitment Increase Agreement, dated as of December 2, 2014 (incorporated by referenceto 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'sCurrent Report on Form 8-K, filed with the Securities and Exchange Commission on November 23, 2015), the Sixth Amendment to CreditAgreement, dated as of May 5, 2017 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed withthe 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 ExchangeCommission 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 byreference 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 Exhibit10.2 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 toExhibit 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 Statementon Schedule 14A, filed with the Securities and Exchange Commission on April 3, 2012), as amended by Amendment Number One to CashIncentive 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 CurrentReport on Form 8-K, filed with the Securities and Exchange Commission on June 16, 2010), as amended by Amendment Number One toLong-Term Stock Incentive Plan, effective as of October 26, 2015 (incorporated by reference to Exhibit 10.2 to the Company's CurrentReport 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 toExhibit 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 QuarterlyReport 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'sQuarterly 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 ExchangeCommission 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 CFOin 2011, 2012 and 2013 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with theSecurities 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 ExchangeCommission 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 ExchangeCommission 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 adoptedJanuary 20, 2014 (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed with the Securities andExchange 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 10.2to 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 toExhibit 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 201810.18+ Form of Restricted Stock Agreement for restricted stock granted to non-employee directors (incorporated by reference to Exhibit 10.6 tothe 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 theCompany'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 byreference to Exhibit 10.42 to the Company's Annual Report on Form 10-K, filed with the Securities and Exchange Commission onFebruary 24, 2015)10.21+ Form of Performance Share Unit Award Agreement for performance share units granted to executive officers in 2016 (incorporated byreference to Exhibit 10.7 to the Company's Annual Report on Form 8-K, filed with the Securities and Exchange Commission on October29, 2015)10.22+ Form of Performance Share Unit Award Agreement for performance share units granted to executive officers in 2017 (incorporated byreference to Exhibit 10.33 to the Company's Annual Report on Form 10-K, filed with the Securities and Exchange Commission onFebruary 22, 2017)10.23*+ Form of Performance Share Unit Award Agreement for performance share units granted to executive officers in 201810.24 Purchase and Sale Agreement, dated June 21, 2016, by and among QEP Energy Company, as purchaser, and RK Petroleum Corp. andvarious other owners of certain oil and gas properties in the Permian Basin, as sellers (incorporated by reference to Exhibit 10.1 to theCompany's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on July 27, 2016), as amended by theFirst Amendment to Purchase and Sale Agreement, dated as of September 7, 2016 (incorporated by reference to Exhibit 10.2 to theCompany's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on October 26, 2016), and the SecondAmendment to Purchase and Sale Agreement, dated September 14, 2016 (incorporated by reference to Exhibit 1.1 to the Company'sCurrent 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., AlpineOil Company, and Kelly Cox, collectively as sellers (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form8-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 andExchange 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 toExhibit 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 ExchangeCommission on October 25, 2017)10.29*+ Form of Retention Bonus Letter Agreement, dated February 26, 2018, between the Company and each of its executive officers10.30*+ Form of Severance Compensation Program Letter Agreement, dated February 26, 2018, between the Company and each of its executiveofficers10.31* Letter Agreement, dated February 28, 2018, by and between QEP Resources, Inc. and Elliott Management Corporation12.1* Ratio of earnings to fixed charges21.1* Subsidiaries of the Company23.1* Consent of Independent Registered Public Accounting Firm – PricewaterhouseCoopers LLP23.2* Consent of Independent Petroleum Engineers and Geologists – Ryder Scott Company, L.P.23.3* Consent of Independent Petroleum Engineers and Geologists – DeGolyer and MacNaughton24* Power of Attorney31.1* Certification signed by Charles B. Stanley, QEP Resources, Inc., Chairman, President and Chief Executive Officer, pursuant to Section302 of the Sarbanes-Oxley Act of 200231.2* Certification signed by Richard J. Doleshek, QEP Resources, Inc. Executive Vice President, Chief Financial Officer, pursuant to Section302 of the Sarbanes-Oxley Act of 200232.1* Certification signed by Charles B. Stanley and Richard J. Doleshek, QEP Resources, Inc. Chairman, President and Chief Executive Officerand Executive Vice President, Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 200299.1* Qualifications and Report of Independent Petroleum Engineers and Geologists – Ryder Scott Company, L.P.101.INS** XBRL Instance Document101.SCH** XBRL Schema Document101.CAL** XBRL Calculation Linkbase Document101.LAB** XBRL Label Linkbase Document101.PRE** XBRL Presentation Linkbase Document101.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 ofthe 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 arenot subject to liability under those sections.+Indicates a management contract or compensatory plan or arrangement130(c) Financial Statements Schedules: All schedules are omitted because they are not applicable or the required information is shown in the ConsolidatedFinancial Statements or Notes thereto.131ITEM 16. FORM 10-K SUMMARYNone.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 itsbehalf 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 OfficerPursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrantand in the capacities indicated on February 28, 2018./s/ Charles B. StanleyChairman, President and Chief Executive OfficerCharles B. Stanley(Principal Executive Officer)/s/ Richard J. DoleshekExecutive Vice President and Chief Financial OfficerRichard J. Doleshek(Principal Financial Officer) /s/ Alice B. Ley Vice President, Controller and Chief Accounting OfficerAlice B. Ley (Principal Accounting Officer)*Charles B. StanleyChairman of the Board; Director*David Trice Director*Julie A. DillDirector*M. W. ScogginsDirector*Mary Shafer Malicki Director*Michael J. Minarovic Director*Phillips S. Baker, Jr. Director*Robert F. HeinemannDirector*William L. Thacker III Director February 28, 2018*By/s/ Charles B. StanleyCharles B. Stanley, Attorney in Fact133Exhibit 10.17QEP RESOURCES INC.2010 LONG-TERM STOCK INCENTIVE PLANRESTRICTED STOCK AGREEMENT THIS RESTRICTED STOCK AGREEMENT (the "Agreement") is made as of [grant date] (the "Effective Date"), between QEP Resources, Inc., aDelaware 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 IncentivePlan, 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 disposedof, 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 inthe Restricted Stock. Upon vesting, the restrictions in this Section 2 shall lapse, the Restricted Stock shall no longer be subject to forfeiture, and Grantee maytransfer 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 anaccount 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 sharesare 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 anannual basis in March or September (depending on grant date) beginning no sooner than eight months after grant date and no later than fourteen months aftergrant 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 bevested.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 theNYSE 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 thenext full day after trading resumes.5. Termination of Employment; Forfeiture of Restricted Stock. If Grantee’s employment with the Company terminates, shares of Restricted Stockshall be treated as follows unless Grantee is subject to an employment agreement or other agreement that governs treatment of Restricted Stock upontermination, 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 VestingDate, 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 within60 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 theRestricted 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 anysuch failure resulting from incapacity due to physical or mental illness), following written demand for substantial performance delivered to Grantee by theBoard or the Chief Executive Officer of the Company; or (ii) willful engagement in conduct that is materially injurious to the Employer. For purposes of thisdefinition, 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 reasonablebelief that Grantee’s action or omission was in the best interests of Grantee’s Employer. The Company, acting through the Board, must notify Grantee inwriting that Grantee’s employment is being terminated for "Cause". The notice shall include a list of the factual findings used to sustain the judgment thatGrantee’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 effectafter 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 inGrantee’s gross annual base salary (as in effect immediately prior to the Change in Control of the Company), target incentive opportunity under any AnnualCash Incentive Plan or long-term incentive award opportunity under any Long-Term Incentive Plan or Stock Incentive Plan; (ii) a material diminution inGrantee’s authority, duties, or responsibilities; (iii) a material diminution in the authority, duties, or responsibilities of the supervisor to whom Grantee isrequired to report, including a requirement that Grantee report to a corporate officer or employee instead of reporting directly to the Board; (iv) a materialdiminution 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 theCompany 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 orcondition. For purposes of this definition:(1) "Annual Cash Incentive Plan" means any annual incentive plan, program or arrangement offered by the Employerpursuant 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 morethan 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 Employerpursuant 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 oneyear, 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 followingvesting 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 theEmployer 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 suchtermination.(d) Manner of Forfeiture. Any shares of Restricted Stock forfeited by Grantee pursuant to this Section 5 shall promptly be transferred to theCompany without the payment of any consideration therefor, and Grantee or Grantee’s attorney-in-fact, shall execute all documents and take all actions asshall 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 stockholderwith 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, theCompany 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 orher 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 enforceits rights to specific performance to the extent permitted by law and may exercise such other equitable remedies then available to it. The Company may refusefor any purpose to recognize any transferee who receives shares contrary to the provisions of this Agreement as a stockholder of the Company and may retainand/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.27. Rights of a Stockholder. Subject to the restrictions imposed by Section 2 and the terms of any other relevant sections hereof, Grantee shall haveall 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 orexchanged 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 beincreased 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 ofshares 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 exchangedor 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 theoutstanding 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 beenexchanged, then if the Committee shall, in its sole discretion, determine that the change equitably requires an adjustment in the shares of Restricted Stock, anadjustment 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, whosedetermination in that respect shall be final, binding and conclusive. Fractional shares resulting from any adjustment to the Restricted Stock pursuant to thisSection 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 makeadjustments, reclassifications, reorganizations or changes of its capital or business structure, to merge, to consolidate, to dissolve, to liquidate or to sell ortransfer 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 theaward of the Restricted Stock. THIS SUMMARY DOES NOT ADDRESS EMPLOYMENT, SPECIFIC STATE, LOCAL OR FOREIGN TAX CONSEQUENCESTHAT MAY BE APPLICABLE TO GRANTEE. GRANTEE UNDERSTANDS THAT THIS SUMMARY IS NECESSARILY INCOMPLETE, AND THE TAXLAWS 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 ofRestricted 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 allapplicable 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 amountrequired 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 thetransfer to the Company, with such shares having an aggregate Fair Market Value equal to the amount required to be withheld or such lesser or greateramount as may be elected by Grantee, up to Grantee’s marginal tax payment obligations associated with the taxation of the Restricted Stock.3 (b) All elections under this Section 10 shall be subject to the approval or disapproval of the Committee. Unless the Committee determinesotherwise or Grantee has notified the Company in writing otherwise, Grantee shall be deemed to have elected the method described in Section 10(a)(iii). Thevalue 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 bedetermined (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 mustsatisfy 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 RevenueService, 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 asof 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 ISGRANTEE’S SOLE RESPONSIBILITY AND NOT THE COMPANY’S TO FILE TIMELY THE ELECTION UNDER SECTION 83(b) OF THE CODE, EVEN IFGRANTEE 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 ADVISORSTHE FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES OF THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT ANDTHAT HE OR SHE IS RELYING SOLELY ON SUCH ADVISORS AND NOT ON ANY STATEMENTS OR REPRESENTATIONS OF THE COMPANY ORANY OF ITS AGENTS. GRANTEE UNDERSTANDS AND AGREES THAT HE OR SHE (AND NOT THE COMPANY) SHALL BE RESPONSIBLE FOR ANYTAX 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 firstclass 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 filewith 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 thecase 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 bythe Company and Grantee, and as approved by the Committee or its delegate. Notwithstanding any provision in this Agreement to the contrary, includingSection 14, an amendment to the Plan that would materially and adversely affect Grantee’s rights with respect to the award of Restricted Stock grantedhereunder 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 ofthis Agreement, the terms of the Plan shall prevail. Capitalized terms used in this Agreement but not defined herein shall have the meaning given such termsin the Plan.15. Construction; Severability. The section headings contained herein are for reference purposes only and shall not in any way affect the meaningor interpretation of this Agreement. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of anyother 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 appointedunder the Plan, but only to the extent permitted under the Plan.417. Entire Agreement; Binding Effect. Once accepted, this Agreement, the terms and conditions of the Plan, and the award of Restricted Stock setforth herein, constitute the entire agreement between Grantee and the Company governing such award of Restricted Stock, and shall be binding upon andinure 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 ofyour 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 thechoice 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 Officer5Exhibit 10.23QEP RESOURCES, INC.CASH INCENTIVE PLANPERFORMANCE SHARE UNIT AWARD AGREEMENTTHIS 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 IncentivePlan (the "Plan"), the Company hereby issues to Grantee the right to receive a number of Performance Share Units calculatedin the manner set forth in Appendix A hereto, based on the achievement of one or more Performance Goals that must beattained 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 andAppendix A hereto represents the right to receive a cash payment equal to the Fair Market Value of one share of theCompany’s no par value common stock ("Common Stock"), subject to Section 3 and the other terms and conditions of thisAgreement. 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 inaccordance with this Agreement and Appendix A hereto only if the Grantee remains in the continuous employment of theCompany and its Affiliates from the Effective Date through the date such earned Performance Share Units are paid inaccordance with Section 3 (the "Vest Date").a)Termination of Employment. Except as provided in subsections (b) and (c) below, if the Grantee terminatesemployment with the Company and its Affiliates for any reason prior to the Vest Date, the Grantee shall forfeit any andall 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 accountof death, Disability, or Retirement (as defined below) prior to the last day of the Performance Period, the Grantee shallreceive on the Vest Date a pro rata portion of the Performance Share Units that would otherwise have been receivedfor the Performance Period, subject to certification by the Committee, in an amount equal to the product of (x) thenumber of Performance Share Units that would have been earned in accordance with the provisions of Appendix A hadGrantee remained in the continuous employment of the Company or its Affiliates through the last day of thePerformance 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 offull months in the Performance Period. If the Grantee terminates employment with the Company and its Affiliates onaccount 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 accordancewith the provisions of Appendix A had the Grantee remained in the continuous employment of the Company or itsAffiliates through the Vest Date. "Retirement" shall mean Grantee’s voluntary termination of employment with theCompany and its Affiliates on or after age 55 with at least 10 years of service; provided that such retirement occurs noearlier than 12 months after the first day of the Performance Period, or such other retirement as shall be approved by theCommittee in its discretion.c)Termination Following a Change in Control. If, upon a Change in Control of the Company or within the three yearsthereafter, the Grantee’s employment is terminated prior to the Vest Date (i) by the Company and its Affiliates for anyreason other than Cause (as defined below) or Disability (it being understood that upon termination for Disability, theprovisions of paragraph (b) above shall apply) or (ii) by the Grantee for Good Reason (as defined below) within 60days following the expiration of the cure period afforded the Company to rectify the condition giving rise to GoodReason, the Grantee shall be entitled to receive a payment for the Performance Share Units earned hereunder based onthe greater of (A) the level of achievement of the applicable performance goals as of immediately prior to the Change inControl 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). Suchpayment will be made to the Grantee within 30 days after the Grantee’s termination of employment. For purposes ofthis subsection (c):i."Cause" means the Grantee’s: (i) willful and continued failure to perform substantially the Grantee’s duties withan Employer (other than any such failure resulting from incapacity due to physical or mental illness), followingwritten demand for substantial performance delivered to the Grantee by the Board or the Chief ExecutiveOfficer of the Company; or (ii) willful engagement in conduct that is materially injurious to an Employer. Forpurposes of this definition, no act or failure to act on the part of the Grantee shall be considered "willful" unlessit is done, or omitted to be done, by the Grantee without reasonable belief that the Grantee’s action or omissionwas in the best interests of the Grantee’s Employer. The Company, acting through the Board, must notify theGrantee in writing that the Grantee’s employment is being terminated for "Cause". The notice shall include a listof 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 writtenconsent, and that remain in effect after notice has been provided by the Grantee to the Company of such eventor condition and the expiration of a 30 day cure period: (i) a material diminution in the Grantee’s gross annualbase salary (as in effect immediately prior to the Change in Control of the Company), target incentiveopportunity 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, orresponsibilities; (iii) a material diminution in the authority, duties, or responsibilities of the supervisor to whomthe Grantee is required to report, including a requirement that the Grantee report to a corporate officer oremployee instead of reporting directly to the Board; (iv) a material diminution in the budget over which theGrantee retains authority; (v) a material change in the geographic location at which the Grantee performsservices; or (vi) any other action or inaction that constitutes a material breach by an Employer of the Grantee’semployment agreement (if any). The Grantee’s notification to the Company must be in writing and must occurwithin a reasonable period of time, not to exceed 90 days, following the initial existence of the relevant event orcondition. For purposes of this definition:A."Annual Cash Incentive Plan" means any annual incentive plan, program or arrangement offeredby an Employer pursuant to which the Grantee is eligible to receive a cash award, subject inwhole or in part to the achievement of performance goals over a period of no more than oneyear, including without limitation the Plan.B."Long-Term Incentive Plan" means any long-term incentive plan, program or arrangementoffered by an Employer pursuant to which the Grantee is eligible to receive an award, subject inwhole 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 whichupon or following vesting or exercise, as applicable, the Grantee is entitled to receive shares ofthe Company’s Common Stock, including without limitation the QEP Resources, Inc. 2010Long-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 thenumber of Performance Share Units that have been earned in accordance with Appendix A and the terms andconditions of this Agreement. Subject tosubsection (b), payment for Performance Share Units shall be made in cash on the Vest Date. The amount distributableshall be based on the average closing Company stock price for the fourth quarter of the final year of the PerformancePeriod. All payments shall be made as soon as administratively practicable after the date on which the Committeedetermines and certifies the number of Performance Share Units that have been earned, but in all events not later thanMarch 15 of the calendar year following the calendar year in which the Performance Period ends. The foregoingprovisions are subject to the terms of any valid and effective deferral election made by the Grantee with respect to thePerformance 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 ofpaying the Performance Share Units in cash as provided in subsection (a), the Committee may elect in its discretion topay some or all of the Performance Share Units in the form of an equal number of actual shares of the Company’s (orits successor’s) Common Stock or other applicable securities, which shares of Common Stock or other applicablesecurities shall be delivered to the Grantee under the Company’s 2010 Long-Term Stock Incentive Plan (as it may beamended or restated from time to time, or, to the extent applicable, any future or successor equity compensation plan ofthe Company).4.No Rights of a Stockholder. The Grantee shall have no voting or other rights as a stockholder of the Company with respect tothis award. The Grantee’s right to receive payments earned under this Agreement shall be no greater than the right of anyunsecured 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 topurchase Common Stock at a price materially below fair market value or other similar corporate event affecting the CommonStock, the Committee shall adjust the award issued hereunder in order to preserve the benefits or potential benefits intended tobe 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 CorporateSecretary, and if to Grantee, to his or her address now on file with the Company, or to such other address as either maydesignate in writing. Any notice shall be deemed to be duly given as of the date delivered in the case of e-mail or personaldelivery, or as of the second day after enclosed in a properly sealed envelope and deposited, postage prepaid, in a United Statespost office, in the case of mailed notice.7.Amendment. Except as provided herein, this Agreement may not be amended or otherwise modified unless evidenced inwriting and signed by the Company and Grantee, or as approved by the Committee or its delegate. Notwithstanding anyprovision in this Agreement to the contrary, including Section 8, an amendment to the Plan that would materially and adverselyaffect Grantee’s rights with respect to the award of Performance Share Units granted hereunder will not be effective withrespect to such award.8.Relationship to Plan. Except to the extent this Agreement provides for the discretionary stock settlement of the Target ShareUnits, this Agreement shall not alter the terms of the Plan. If there is a conflict between the terms of the Plan and the terms ofthis Agreement, the terms of the Plan shall prevail, provided, however, that the terms of Section 3(b) of this Agreement shallcontrol over any contrary provision of the Plan. Capitalized terms used in this Agreement but not defined herein shall have themeaning given such terms in the Plan.9.Construction; Severability. The section headings contained herein are for reference purposes only and shall not in any wayaffect the meaning or interpretation of this Agreement. The invalidity or unenforceability of any provision of this Agreementshall not affect the validity or enforceability of any other provision of this Agreement, and each other provision of thisAgreement 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 theCommittee 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 ofPerformance Share Units set forth herein, constitute the entire agreement between Grantee and the Company governing suchaward of Performance Share Units, and shall be binding upon and inure to the benefit of the Company and to Grantee and tothe 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 retainedin the employ of the Company or its Affiliates and this Agreement is limited solely to governing the rights and obligations ofGrantee 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 allpayments 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 ATO THE PERFORMANCE SHARE UNIT AWARD AGREEMENTDetermination of Target Share UnitsThe dollar value of the award, as determined by the Committee, is denominated in Target Share Units based on the closing price ofCompany Common Stock on the date of the award (March 1, 2018).Performance PeriodThe Performance Period is January 1, 2018 through December 31, 2020.Performance GoalsThe performance measure for the award is the Company’s total shareholder return (TSR) compared to the TSR of a group of peercompanies. TSR combines share price appreciation and dividends paid to show the total return to the shareholder. Although TSR willvary 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 theCompany’s beginning stock price, divided by (ii) the Company’s beginning stock price. For both the beginning and ending stockprices, the calculation uses the average closing price during the previous quarter (i.e., beginning price is the average during Q4 2017and the ending price is the average during Q4 2020). This calculation is used instead of the actual closing price on the given date tosmooth 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 pricePeer GroupThe following companies are included in the Company’s peer group:Callon Petroleum Co/DEMatador Resources CoCarrizo Oil & Gas IncNewfield Exploration CoCentennial Resource Development IncOasis Petroleum IncCimarex Energy CoParsley Energy IncDiamondback Energy IncPDC Energy IncEnergen CorpRange Resources IncEP Energy CorpRSP Permian IncExtraction Oil & Gas IncSM Energy CoGulfport Energy CorpSouthwestern Energy CoJagged Peak Energy IncWhiting Petroleum CorpLaredo Petroleum IncWPX Energy IncShould a peer company file a bankruptcy or similar petition or otherwise seek any protection from creditors under an available legalprocess or cease to exist as a separate publicly-traded company during the Performance Period (e.g., due to acquisitions, etc.), it willnonetheless remain as a member of the Company’s peer group for purposes of the Payout Calculation described below and theCompany 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 theCompany’s peer group over the three-year period. The Company’s TSR is ranked among the TSR of all peer companies and thepercentile rank is calculated based on the Company’s position in the ranking (e.g. if the Company’s TSR ranks 13th out of 25companies, the Company is at the 50th percentile). The performance scale is detailed in the following table, with interpolation betweenthe 30th and 90th Percentile Ranks.Company’s Percentile Rank in PeerGroupShares Earned as Percent ofTarget (Performance %)90th Percentile or Above200%70th Percentile150%50th Percentile100%30th Percentile50%Below 30th Percentile0%Notwithstanding the foregoing, in the event the Company’s TSR is between negative 25% and 0% on an absolute cumulative basis overthe Performance Period, then the Performance Percentage for this performance measure will not be more than 150%, and in the eventthe Company’s TSR is less than negative 25% on an absolute cumulative basis over the Performance Period, then the PerformancePercentage for this performance measure will not be more than 100% (i.e., the Performance Percentage for this performance measure iscapped at 150% if the Company’s shareholders experience a negative return over the Performance Period and it is capped at 100% ifthe total negative return over the Performance Period is worse than negative 25%). In addition, notwithstanding the foregoing, if QEP’saverage annualized TSR over the Performance Period is equal to or greater than 15% (assuming annual compounding), then thePerformance Percentage for this performance measure will not be less than 50% (i.e., there is a 50% floor on the PerformancePercentage 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 closingCompany stock price for the fourth quarter of 2020. The actual payout under the Plan at the end of the Performance Period, as set forthin 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 fourthquarter of the final year of the Performance Period)Exhibit 10.29February 26, 2018[NAME]Re: Executive Retention BonusDear [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 asupplemental benefit that is in addition to the Severance Benefits (as defined in the Participation Letter) that may become payable toyou 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 mustbe done within 15 days of the date of this Retention Bonus Letter written above, you acknowledge and agree to all of the terms andconditions 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, theCompany is offering you a one-time special cash retention bonus in an amount equal to $500,0001 (the "Retention Bonus"). TheRetention Bonus is subject to your continued employment with the Company through March 1, 2019 (the "Retention Date") and shallbe paid in a lump sum within 15 days after the Retention Date, provided, however, that if your employment is terminated by theCompany without Cause (as defined in the Participation Letter) (and other than due to your death or Disability (as defined in theParticipation Letter)) or you resign your employment for Good Reason (as defined in the Participation Letter), in either case prior to theRetention Date and you satisfy the requirements for receiving any Severance Benefits in accordance with the terms of the ParticipationLetter, 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) youremained employed following the date of this Retention Bonus Letter) will be paid to you (the "Pro-Rated Retention Bonus"), inaddition to such Severance Benefits, at the same time as the Cash Severance (as defined in the Participation Letter) is paid to you. Forthe avoidance of doubt, the Pro-Rated Retention Bonus will be paid to you in the event you do not receive certain Severance Benefits asa result of the application of Section 7 of the Participation Letter, provided that you execute and do not revoke a release of claims in theform attached as an exhibit to the Participation Letter. The Retention Bonus is a special payment to you and will not be taken intoaccount 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 asexpressly 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 agreementbetween you and the Company with respect to the subject matter herein and it supersedes any other promises, warranties orrepresentations 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 orbe exempt from Section 409A of the Internal Revenue Code of 1986, as amended, and the regulations and guidance promulgatedthereunder (collectively, "Section 409A") and, accordingly, to the maximum extent permitted, this Retention Bonus Letter shall beinterpreted to be in compliance therewith. Notwithstanding anything in this Retention Bonus Letter to the contrary, any compensation orbenefits payable under this Retention Bonus Letter that is considered nonqualified deferred compensation under Section 409A and isdesignated under this Retention Bonus Letter as payable upon Participant’s termination of employment shall be payable only uponParticipant’s "separation from service" with the Company within the meaning of Section 409A (a "Separation from Service"). Inaddition, notwithstanding anything in this Retention Bonus Letter to the contrary, if Participant is deemed by the Company at the timeof Participant’s Separation from Service to be a "specified employee" for purposes of Section 409A, to the extent delayedcommencement of any portion of the benefits to which Participant is entitled under this Retention Bonus Letter is required in order toavoid a prohibited distribution under Section 409A, such portion of Participant’s benefits shall not be provided to Participant prior to theearlier of (i) the expiration of the six-month period measured from the date of Participant’s Separation from Service with the Companyor (ii) the date of Participant’s death. Upon the first business day following the expiration of the applicable Section 409A period, allpayments 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 Lettershall 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 Letterthat the parties cannot resolve through negotiation shall be settled solely and exclusively by a binding arbitration process administeredby the American Arbitration Association ("AAA") in Denver Colorado. Such arbitration shall be conducted in accordance with theAAA’s then-existing Employment Arbitration Rules. Each party shall bear its own attorney’s fees and expenses and one-half of the feesand expenses of the arbitration; provided, that the arbitrator shall have the authority to apportion the costs of arbitration and to render anaward including reasonable attorneys’ fees, as and to the extent the arbitrator deems appropriate under the circumstances. Thearbitrator’s decisions and awards will be rendered in a reasoned written opinion, and the parties agree to abide by all such decisions andawards. Such decisions and awards rendered by the arbitrator shall be final and conclusive and may be entered in any court havingjurisdiction.5) Miscellaneous. All payments to the Participant in accordance with the provisions of the Plan shall be subject to applicablewithholding of local, state, Federal and foreign taxes, as determined in the sole discretion of the Company. Except as expressly set forthherein, your employment relationship with the Company remains at will, meaning that either you or the Company may terminate youremployment at any time, with or without cause or advance notice. Nothing in this letter is intended to or should be construed tocontradict, modify or alter your employment relationship with the Company. The Company’s obligation to make the payments providedfor 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 thisletter, you hereby agree that this letter may only be amended or modified by a written instrument signed by you and a duly authorizedrepresentative 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 andto 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 OfficerACCEPTED AND AGREED TO this ____ day of February 2018.By: [NAME]Exhibit 10.30February 26, 2018[NAME]Re: Executive Severance Compensation ProgramDear [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 isterminated 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 bedone within 15 days of the date of this Participation Letter written above, you acknowledge and agree to all of the terms and conditionsset 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 Companywithout Cause (and other than due to the Participant’s death or Disability) or the Participant resigns the Participant’s employment forGood Reason, then, in either case, provided that (i) the Participant signs, within 45 days after the date of termination, and does notrevoke a release of claims substantially in the form attached hereto as Exhibit A (the "Release"), (ii) returns to the Company all propertybelonging to the Company, (iii) until the applicable date(s) of payment complies with any and all confidentiality and other restrictivecovenants to which the Participant is subject ("Restrictive Covenants") (provided that nothing herein shall be construed to limit theduration of any restrictive covenants), and (iv) promptly resigns from any position as an officer, director or fiduciary of any subsidiaryor affiliate of the Company (and takes any action reasonably requested by the Company to effectuate such resignation), the Participantshall be entitled to receive the following severance payments and benefits (the "Severance Benefits"), which shall be in lieu of and notin 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 theCompany’s annual cash incentive plan, payable within 30 days after the date the Participant signs the Release, but in no eventlater 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 annualcash 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 theParticipant 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-forfeitableand exercisable or payable, as applicable, as of the Participant’s date of termination of employment, provided that, foradministrative 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/orpayment, as applicable, and the Participant’s outstanding stock options shall remain exercisable until the original expiration dateof the options (subject to the general terms of the Company’s applicable equity or long-term incentive plan under which suchoptions 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 monthended prior to the date of termination (the "PSU Measurement Date") and (ii) as applicable, the Company’s average closingCompany stock price for the three month period ending on the PSU Measurement Date, provided, further, that to the extent theapplicable performance level cannot be measured prior to the end of the applicable performance period, the payment ofParticipant’s Performance Share Units shall be based on the actual level of performance achievement at the end of theperformance 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 monthlypremium 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 ConsolidatedOmnibus Budget Reconciliation Act of 1985, as amended ("COBRA"), payable within 30 days after the date the Participantsigns 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 preferredoutplacement 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 amendedfrom time to time and including successor plans, the "Retirement Plan") and/or the QEP Resources, Inc. Supplemental ExecutiveRetirement Plan (as amended from time to time and including successor plans, the "SERP"), then Participant shall be entitled toan 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 theCompany’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 bonusesfor 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 Participanthad 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 Participantwas 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 (ifparticipating) as of the Date of Termination, and (B) the Participant’s compensation under the Retirement Plan and the SERP (ifparticipating) for each additional year of such service had been equal to the Participant’s compensation for the last full Yearprior to the date of termination, over (ii) the actual benefit accrued under the Retirement Plan and the SERP (if participating) asof the Date of Termination. Such enhanced retirement benefit shall be paid in a single lump sum within 30 days after the datethe 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 interestrate equal to 80 percent of the average of the IRS 30-year Treasury Securities Rates for the six-month period preceding theparticipant’s date of termination, plus (ii) interest on such amount, credited monthly from the date of termination through thedate of payment (taking into account any delay required by Section 5.7(b)), using the appropriate 30-year Treasury bond ratequoted in the Wall Street Journal on the first business day of each month. The appropriate 30-year Treasury bond shall be thebond 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 ordishonesty; (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 writtendemand for substantial performance delivered to the Participant by the Company’s Board of Directors (the "Board") or the ChiefExecutive Officer of the Company and a reasonable opportunity to cure; (iii) violation of any Restrictive Covenants; (iv) willfulfailure to comply with Board directives or material Company policies, following written demand for compliance delivered to theParticipant by the Board or the Chief Executive Officer of the Company and a reasonable opportunity to cure; or (v) the willfulengaging by the Participant in fraud or misconduct that materially and adversely affects the Participant’s Employer or theCompany. 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 wasin the best interests of the Company. The Company, acting through the Board, must notify the Participant in writing that theParticipant’s employment is being terminated for "Cause". The notice shall include a list of the factual findings used to sustainthe 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 QEPResources, Inc. Long-term Disability Plan or any plan providing similar long-term disability benefits sponsored by the Companyor 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 theexpiration of a 30 day cure period: (i) a material diminution in the Participant’s base salary, target bonus opportunity under theCompany’s annual incentive plan, or target annual award opportunity under the Company’s long-term incentive compensationplans, it being understood that any such diminution that results in a reduction in total target annual compensation of 5% or moreshall be deemed material; (ii) a material diminution in the Participant’s authority, duties, or responsibilities (which shall include achange in reporting structure that requires the Participant to report to a supervisor having materially less authority within theCompany, it being understood that a mere change in the identity or role of the Participant’s supervisor shall not constitute GoodReason hereunder). For the avoidance of doubt, a diminution in the Participant’s authority, duties or responsibilities arising as asole result of the divestiture of assets shall not constitute Good Reason hereunder; or (iii) a material change in the geographiclocation at which the Participant is required to perform services. The Participant’s notification to the Company must be inwriting and must occur within a reasonable period of time, not to exceed 60 days, following the date the Participant knew orshould 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 tothe 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 SeveranceCompensation 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 furtherforce or effect, on September 30, 2020. In addition, in the event a Change in Control (as defined in the CIC Plan) occurs, you will nolonger be eligible to receive the Severance Benefits under this Participation Letter and will instead be eligible to receive SeparationBenefits (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 beexempt from Section 409A of the Internal Revenue Code of 1986, as amended, and the regulations and guidance promulgatedthereunder (collectively, "Section 409A") and, accordingly, to the maximum extent permitted, this Participation Letter shall beinterpreted to be in compliance therewith. Notwithstanding anything in this Participation Letter to the contrary, any compensation orbenefits payable under this Participation Letter that is considered nonqualified deferred compensation under Section 409A and isdesignated under this Participation Letter as payable upon Participant’s termination of employment shall be payable only uponParticipant’s "separation from service" with the Company within the meaning of Section 409A (a "Separation from Service"). Inaddition, notwithstanding anything in this Participation Letter to the contrary, if Participant is deemed by the Company at the time ofParticipant’s Separation from Service to be a "specified employee" for purposes of Section 409A, to the extent delayed commencementof any portion of the benefits to which Participant is entitled under this Participation Letter is required in order to avoid a prohibiteddistribution under Section 409A, such portion of Participant’s benefits shall not be provided to Participant prior to the earlier of (i) theexpiration of the six-month period measured from the date of Participant’s Separation from Service with the Company or (ii) the date ofParticipant’s death. Upon the first business day following the expiration of the applicable Section 409A period, all payments deferredpursuant 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 Lettershall be paid as otherwise provided herein.6) Governing Law; Arbitration. The validity, interpretation, construction and performance of this Participation Letter shallin all respects be governed by the laws of Colorado without reference to principles of conflict of law, except to the extent pre-emptedby Federal law. The parties agree that any controversy, claim or dispute arising out of or relating to this Participation Letter that theparties cannot resolve through negotiation shall be settled solely and exclusively by a binding arbitration process administered by theAmerican Arbitration Association ("AAA") in Denver Colorado. Such arbitration shall be conducted in accordance with the AAA’sthen-existing Employment Arbitration Rules. Each party shall bear its own attorney’s fees and expenses and one-half of the fees andexpenses of the arbitration; provided, that the arbitrator shall have the authority to apportion the costs of arbitration and to render anaward including reasonable attorneys’ fees, as and to the extent the arbitrator deems appropriate under the circumstances. Thearbitrator’s decisions and awards will be rendered in a reasoned written opinion, and the parties agree to abide by all such decisions andawards. Such decisions and awards rendered by the arbitrator shall be final and conclusive and may be entered in any court havingjurisdiction.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 inconnection with such Divestiture, (i) the Buyer offers to employ the Participant in a comparable role or position and (ii) the Participantaccepts such offer of employment and/or commences employment with the Buyer following the closing of the Divestiture, then theParticipant will not be entitled to receive the Severance Benefits described in Section 1(a), (d) or (e) of this Participation Letter if theParticipant’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 applicablewithholding of local, state, Federal and foreign taxes, as determined in the sole discretion of the Company. Except as expressly set forthherein, your employment relationship with the Company remains at will, meaning that either you or the Company may terminate youremployment at any time, with or without cause or advance notice. Nothing in this letter is intended to or should be construed tocontradict, modify or alter your employment relationship with the Company. The Company’s obligation to make the payments providedfor 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, youhereby agree that this letter may only be amended or modified by a written instrument signed by you and a duly authorizedrepresentative of the Company. This Participation Letter shall bind any successor of the Company, its assets or its businesses (whetherdirect or indirect, by purchase, merger, consolidation, separation or otherwise), in the same manner and to the same extent that theCompany 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 AForm of Release of Claims[The language in this Release may change based on legal developments and evolving best practices; this form is provided as anexample 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’sexecution of this Release; andWHEREAS, 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, theadequacy of which is hereby acknowledged by Executive, and which Executive acknowledges that he or she would not otherwise beentitled 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 orlimited partners, employees, attorneys, creditors, agents and representatives, and the employee benefit plans in which Executive is orhas 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 kindand 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 orcircumstances arising or occurring on or prior to the date hereof, arising directly or indirectly out of, relating to, or in any other wayinvolving in any manner whatsoever Executive’s employment by or service to the Company or the termination thereof, including anyand all claims arising under federal, state, or local laws relating to employment, including without limitation claims of wrongfuldischarge, breach of express or implied contract, fraud, misrepresentation, defamation, or liability in tort, and claims of any kind thatmay be brought in any court or administrative agency including, without limitation, claims under Title VII of the Civil Rights Act of1964, as amended, 42 U.S.C. Section 2000, et seq.; the Americans with Disabilities Act, as amended, 42 U.S.C. § 12101 et seq.; theRehabilitation Act of 1973, as amended, 29 U.S.C. § 701 et seq.; the Civil Rights Act of 1866, and the Civil Rights Act of 1991; 42U.S.C. Section 1981, et seq.; the Age Discrimination in Employment Act, as amended, 29 U.S.C. Section 621, et seq. (the "ADEA"); theEqual 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,et seq.; the Family and Medical Leave Act, as amended,29 U.S.C. § 2601 et seq.; the Fair Labor Standards Act of 1938, as amended, 29 U.S.C. § 201 et seq.; the Employee Retirement IncomeSecurity Act, as amended, 29 U.S.C. § 1001 et seq.; 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 statelaw;(ii) Claims for workers’ compensation insurance benefits under the terms of any worker’s compensation insurance policy orfund 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 applicableinsurance policy with respect to Executive’s liability as an employee, director or officer of the Company pursuant to whichExecutive 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 theAgreement;(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 bereleased under such applicable law.(b) Executive acknowledges that this Release was presented to him or her on the date indicated above and that Executive isentitled to have [twenty-one (21)/forty-five (45)] days’ time in which to consider it. Executive further acknowledges that the Companyhas 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 ofhis or her choice before signing this Release, and Executive has had sufficient time to consider the terms of this Release. Executiverepresents 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 thatExecutive 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 hisor her execution of it. Executive understands that this Release will not become effective and enforceable unless the seven (7) dayrevocation period passes and Executive does not revoke the Release in writing. Executive understands that this Release may not berevoked after the seven (7) day revocation period has passed. Executive also understands that any revocation of this Release must bemade 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 inclause (c) above.2. No Assignment. Executive represents and warrants to the Company Releasees that there has been no assignment or othertransfer 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 permittedby law, disclose or divulge to any other person or entity, directly or indirectly, any confidential records or information regarding theCompany, 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, itscomputers (including data stored thereon) and peripherals, Company credit and fuel cards, and keys. Executive may retain incidentalmaterials 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 andintentionally acquired any such materials in preparation for Executive’s termination of employment. Executive represents and warrantsthat in the event he has any Company work related materials, he has no intention of utilizing said materials, nor of disclosing same toany other person or entity.(b) Non-solicitation. For a period of twelve (12) months after the date of Executive’s termination of employment, Executiveagrees not to induce, attempt to induce or solicit any employee of the Company to leave the employ of the Company or any of itsrelated entities, or hire any such employee in any business or other capacity. Notwithstanding the foregoing, if any employee of theCompany initiates contact with Employee as a result of a publically advertised position for purposes of obtaining employment withExecutive 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 competentjurisdiction, such provision shall be deemed modified to the extent necessary to allow enforceability of the provision as so limited, itbeing intended that the Parties shall receive the benefit contemplated herein to the fullest extent permitted by law. If a deemedmodification is not satisfactory in the judgment of such arbitrator or court, the unenforceable provision shall be deemed deleted, and thevalidity 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 ininterpreting this agreement. This Release has been drafted by legal counsel representing the Company, but Executive has participated inthe negotiation of its terms. Furthermore, Executive acknowledges that Executive has had an opportunity to review and revise theRelease and have it reviewed by legal counsel, if desired, and, therefore, the normal rule of construction to the effect that anyambiguities are to be resolved against the drafting party shall not be employed in the interpretation of this Release. Either party’s failureto enforce any provision of this Release shall not in any way be construed as a waiver of any such provision, or prevent that partythereafter 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 UnitedStates of America and the State of Colorado applicable to contracts made and to be performed wholly within such State, and withoutregard to the conflicts of laws principles thereof. The parties agree that any controversy, claim or dispute arising out of or relating to thisAgreement that the partiescannot resolve through negotiation shall be settled solely and exclusively by a binding arbitration process administered by theAmerican Arbitration Association ("AAA") in Denver Colorado. Such arbitration shall be conducted in accordance with the AAA’sthen-existing Employment Arbitration Rules. Each party shall bear its own attorney’s fees and expenses and one-half of the fees andexpenses of the arbitration; provided, that the arbitrator shall have the authority to apportion the costs of arbitration and to render anaward including reasonable attorneys’ fees, as and to the extent the arbitrator deems appropriate under the circumstances. Thearbitrator’s decisions and awards will be rendered in a reasoned written opinion, and the parties agree to abide by all such decisions andawards. Such decisions and awards rendered by the arbitrator shall be final and conclusive and may be entered in any court havingjurisdiction.7. Entire Agreement. This Release and the Agreement constitute the entire agreement of the Parties in respect of the subjectmatter 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 authorizedrepresentative 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 butall 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 writtenabove.EXECUTIVE [ ] By: Print Name: Print Name: Title: Exhibit 10.31QEP RESOURCES, INC.1050 17th StreetDenver, CO 80265February 28, 2018Elliott Management Corporation40 West 57th StreetNew York, NY 10019-4001Attention: Andrew TaylorLadies and Gentlemen:This letter (this "Agreement") constitutes the agreement between Elliott Management Corporation ("Elliott") and QEPResources, 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 dayafter 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 statementinconsistent with the Company Press Release in connection with the announcement of this Agreement. Elliott shall not, and shall causeits 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 thedate of this Agreement), the Company shall file a Current Report on Form 8-K (the "Company 8-K") and/or an Annual Report onForm 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 beconsistent 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 tovote on a binding amendment to the Company’s Amended and Restated Certificate of Incorporation effecting an immediatedeclassification 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 ofapproving the Declassification Amendment. The Declassification Amendment will be presented to the Company’s stockholders forvote at the 2018 Annual Meeting. In connection with the Declassification Amendment, all of the current members of the Board, otherthan Mr. Thacker, will tender their resignations prior to the 2018 Annual Meeting, to be effective prior to the vote for directors at suchmeeting with the intention that should the Declassification Amendment be approved by the Company’s stockholders, all of thedirectors (other than Mr. Thacker) shall serve until the 2019 Annual Meeting, or until their1earlier resignation or retirement from the Board, and that Mr. Thacker will serve his remaining term which expires at the 2019 AnnualMeeting.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 theDeclassification Amendment, (b) solicit proxies for the election of each of the Company’s nominees and the approval of theDeclassification Amendment, (c) cause all Company common stock represented by proxies granted to it (or any of its officers, directorsor representatives) to be voted in favor of approval of the Declassification Amendment, and (d) cause all Company common stockrepresented by proxies granted to it (or any of its officers, directors or representatives) to be voted in favor of each of the Company’snominees. In connection with the 2018 Annual Meeting (and any adjournments or postponements), Elliott shall cause to be present forquorum purposes and vote or cause to be voted any Company common stock that Elliott or its controlling or controlled Affiliates hasthe right to vote on the record date for the 2018 Annual Meeting and is beneficially owned by Elliott or its controlling or controlledAffiliates in favor of (i) the Declassification Amendment, (ii) the election of directors nominated by the Board, and (iii) otherwise inaccordance 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 thisparagraph 4 terminate as provided herein (such period, the "Restricted Period"), Elliott shall not, and shall cause its Affiliates and itsand 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 theelection or removal of directors of the Company or any of its subsidiaries or any other matter or proposal relating to theCompany or any of its subsidiaries or become a "participant" (as such term is used in the proxy rules of the SEC) in any suchsolicitation 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 encouragementor 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 respectto 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, anyVoting Securities of the Company, or engage in any swap or hedging transactions or other derivative agreements of any naturewith respect to Voting Securities, in each case, if such acquisition, offer, agreement or transaction would2result in Elliott having a Net Long Position of, or voting rights (or the right to acquire voting rights) with respect to, more than9.9% 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, exchangeoffer, merger, consolidation, acquisition, business combination, purchase of a division, purchase of all or substantially all of theassets, recapitalization, restructuring, liquidation, dissolution or similar extraordinary transaction involving the Company or anyof its subsidiaries or its or their respective securities or assets (each, an "Extraordinary Transaction") (it being understood thatthe foregoing shall not restrict the Restricted Persons from tendering shares, receiving payment for shares or otherwiseparticipating in any Extraordinary Transaction initiated by a Third Party on the same basis as other stockholders of theCompany or any of its subsidiaries, or from participating in any Extraordinary Transaction that has been approved by the Boardor the board of any subsidiary of the Company), provided that in no case will any asset sales (or series of asset sales) consistentwith the strategic initiatives announced in the Company Press Release be an Extraordinary Transaction; or make, directly orindirectly, any proposal, either alone or in concert with others, to the Company or any of its subsidiaries or the Board or theboard of any subsidiary of the Company that would reasonably be expected to require the Company or Elliott to make a publicannouncement 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 toany voting trust, arrangement or agreement other than (i) this Agreement, (ii) solely with Affiliates of Elliott, or (iii) grantingproxies 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 anysubsidiary of the Company or nominate or propose the nomination of, or recommend the nomination of, any candidate to theBoard or any such other board, (ii) seek, alone or in concert with others, the removal of any member of the Board or any suchother board, or (iii) conduct a referendum of stockholders of the Company or any of its subsidiaries; provided that nothing inthis Agreement shall prevent Elliott or its Affiliates from taking actions confidentially in furtherance of identifying directorcandidates in connection with the 2019 Annual Meeting so long as such actions do not create a public disclosure obligation forElliott or the Company and are undertaken on a confidential basis and in accordance in all material respects with Elliott’snormal 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 Section220 of the General Corporation Law of the State of Delaware or other statutory or regulatory provisions providing forshareholder access to books and records;3(k) except as set forth herein, make any public proposal with respect to (i) any change in the number or term of directors or thefilling of any vacancies on the Board or the board of any subsidiary of the Company, (ii) any material change in thecapitalization 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 futurechange 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 ofits subsidiaries to be delisted from, or to cease to be authorized to be quoted on, any securities exchange or (vi) causing a classof equity securities of the Company or any of its subsidiaries to become eligible for termination of registration pursuant toSection 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 itssubsidiaries or any of its or their respective current or former directors or officers (including derivative actions) in order to effector take any of the actions expressly prohibited by this paragraph 4; provided, however, that for the avoidance of doubt, theforegoing 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) exercisingstatutory appraisal rights; provided, further, that the foregoing shall also not prevent the Restricted Persons from responding toor 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 prohibitedfrom 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 wouldreasonably 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 forany such breach, five (5) business days after written notice is delivered to the Company by Elliott following a material breach of thisAgreement by the Company if such breach has not been cured within such notice period; provided further, that Elliott is not in materialbreach of this Agreement at the time such notice is given; (ii) the announcement by the Company that it (x) has entered into a definitiveagreement, or (y) is negotiating with any Third Party regarding a commercially reasonable offer (which it intends to4pursue in good faith to enter into an Extraordinary Transaction), in each case with respect to any Extraordinary Transaction that wouldresult in the acquisition by any Person of more than 50% of the Voting Securities of the Company; (iii) the commencement of anytender or exchange offer (by any Person other than Elliott or its Affiliates) which, if consummated, would constitute an ExtraordinaryTransaction that would result in the acquisition by any Person of more than 50% of the Voting Securities, where the Company fileswith the SEC a Schedule 14D-9 (or any amendment thereto) that does not recommend that its stockholders reject such tender orexchange offer (provided that nothing herein shall prevent the Company from issuing a “stop, look and listen” communication pursuantto Rule 14d-9(f) promulgated under the Exchange Act in response to the commencement of any tender or exchange offer); (iv) thepublic 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 deliversto its stockholders any preliminary proxy statement, definitive proxy statement or other proxy materials in connection with the 2018Annual Meeting that is inconsistent with the terms of this Agreement; (vi) the adoption by the Board of any amendment to theCompany’s Governing Documents, each as in effect on the date hereof, that would reasonably be expected to impair the ability of astockholder to submit nominations of individuals for election to the Board or stockholder proposals in connection with any AnnualMeeting after the 2018 Annual Meeting; and (vii) the adoption of any shareholder rights plan (unless such rights plan has a trigger inexcess 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 shallprevent Elliott from making (i) any public or private statement or announcement with respect to any Extraordinary Transaction that ispublicly announced by the Company or a Third Party, or (ii) any factual statement made to comply with any subpoena or other legalprocess or respond to a request for information from any governmental authority with jurisdiction over Elliott from whom informationis 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 orencumbrances on any claims or interests in favor of a bank or broker-dealer or prime broker holding such claims or interests in custodyor prime brokerage in the ordinary course of business, which lien or encumbrance is released upon the transfer of such claims orinterests 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 theirrespective Affiliates and its and their respective principals, directors, members, general partners, officers, employees and agents andrepresentatives acting on their behalf not to make or cause to be made any statement or announcement, including in any document orreport filed with or furnished to the SEC or through the press, media, analysts or other Persons, that constitutes an ad hominem attackon, or otherwise disparages, defames, slanders, impugns or is reasonably likely to damage the reputation of, (a) in the case ofstatements or announcements by any of Elliott, the Company or any of its Affiliates, subsidiaries or advisors, or any of its or theirrespective 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’sadvisors. The foregoing shall not (i) restrict the ability of any Person to comply with5any subpoena or other legal process or respond to a request for information from any governmental authority with jurisdiction over thePerson from whom information is sought or (ii) apply to any private communications between Elliott, its Affiliates and its and theirrespective principals, directors, members, general partners, officers, employees or agents or representatives acting on their behalf, onthe one hand, and the Company or any of its subsidiaries, directors, officers, employees or agents or representatives acting on theirbehalf, on the other hand.6. As used in this Agreement, the term (a) "Affiliate" shall have the meaning set forth in Rule 12b-2 promulgatedunder 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’semployees or principals serves as a member of its board of directors or similar governing body, unless such Person otherwise controlssuch entity (as the term "control" is defined in Rule 12b-2 promulgated by the SEC under the Exchange Act); provided further thatwith 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 ExchangeAct; (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 periodestablished pursuant to the Company’s bylaws for stockholders to deliver notice to the Company of director nominations to be broughtbefore the 2019 Annual Meeting; (g) "Net Long Position" shall mean, with respect to any Person, such Person’s net long position, asdefined in Rule 14e-4 under the Exchange Act, mutatis mutandis, in respect of the Company’s common stock; provided that, for theavoidance of doubt, "Net Long Position" will not include any shares as to which such Person does not have the right to vote or directthe vote or as to which such Person has entered into a derivative contract or other agreement, arrangement or understanding that hedgesor transfers, in whole or in part, any of the economic consequences of ownership of such shares; (h) "Person" shall be interpretedbroadly to include, among others, any individual, general or limited partnership, corporation, limited liability or unlimited liabilitycompany, joint venture, estate, trust, group, association or other entity of any kind or structure; (i) "SEC" means the United StatesSecurities and Exchange Commission; (j) "Third Party" shall mean any Person that is not a Party or an Affiliate thereof, a member ofthe Board, a director or officer of the Company, or legal counsel to any Party; and (k) "Voting Securities" shall mean the shares ofcommon stock of the Company and any other securities thereof entitled to vote in the election of directors, or securities convertibleinto, or exercisable or exchangeable for, such shares or other securities, whether or not subject to the passage of time or othercontingencies; 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 byit and is a valid and binding obligation of Elliott, enforceable against it in accordance with its terms; (b) as of the date of thisAgreement, Elliott6beneficially owns an aggregate of 11,700,000 shares of Voting Securities of the Company, of which 10,500,000 are shares of commonstock of the Company; and (c) this Agreement does not violate any law, any order of any court or other agency of government, orElliott’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 byit and is a valid and binding obligation of the Company, enforceable against the Company in accordance with its terms; (b) thisAgreement does not require the approval of the stockholders of the Company; and (c) this Agreement does not violate any law, anyorder of any court or other agency of government, or the Company’s Governing Documents, each as in effect on the date of thisAgreement.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 thisagreement. Without prejudice to any other rights and remedies otherwise available to a Party under this agreement, (a) each Party shallbe entitled to seek equitable relief by way of injunction or otherwise to prevent breaches or threatened breaches of any of theprovisions of this Agreement, without proof of actual damages; (b) the breaching Party shall not plead in defense thereto that therewould be an adequate remedy at law; and (c) the breaching Party agrees to waive any applicable right or requirement that a bond beposted by the non-breaching Party. Such remedies shall not be the exclusive remedies for a breach of this Agreement, but shall be inaddition to all other remedies available at law or in equity. This Agreement is solely for the benefit of the Parties and shall not beenforceable by any other Person.10. This Agreement constitutes the only agreement between Elliott and the Company with respect to the subjectmatter hereof and supersedes all prior agreements, understandings, negotiations and discussions, whether oral or written. ThisAgreement shall be binding upon and inure to the benefit of the Parties and their respective successors and permitted assigns. No Partymay assign or otherwise transfer either this Agreement or any of its rights, interests, or obligations under this Agreement without theprior 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 Partyaffected thereby, and then only in the specific instance and for the specific purpose stated therein. Any waiver by any Party of a breachof 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 anybreach of any other provision of this Agreement. The failure of a Party to insist upon strict adherence to any term of this Agreement onone or more occasions shall not be considered a waiver or deprive that Party of the right thereafter to insist upon strict adherence to thatterm or any other term of this Agreement. If any provision of this Agreement is held invalid or unenforceable by any court ofcompetent jurisdiction, the other provisions of this Agreement shall remain in full force and effect. Any provision of this Agreementheld 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 provisionthat will achieve, to the extent possible, the purposes of such invalid or unenforceable provision. All attorneys’ fees, costs and expensesincurred in connection with this Agreement and all matters related hereto will be paid by the Party incurring such fees, costs orexpenses. Each of the7parties acknowledges that it has been represented by counsel of its choice throughout all negotiations that have preceded the executionof this Agreement, and that it has executed this Agreement with the advice of such counsel. Each Party and its counsel cooperated andparticipated in the drafting and preparation of this Agreement, and any and all drafts relating thereto exchanged among the Parties shallbe 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 anyParty that drafted or prepared it is of no application and is expressly waived by each of the Parties, and any controversy overinterpretations 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 withoutgiving effect to the choice of law principles of such state. Each Party irrevocably and unconditionally consents to the exclusiveinstitution and resolution of any action, suit or proceeding of any kind or nature with respect to or arising out of this Agreementbrought by any Party in the Chancery Court of the State of Delaware and the appellate courts thereof. Each Party irrevocably andunconditionally waives any objection to the laying of venue of any action, suit or proceeding arising out of this agreement in suchcourt, and further irrevocably and unconditionally waives and agrees not to plead or claim in any such court that any such action, suitor proceeding brought in any such court has been brought in an inconvenient forum. The Parties agree that a final judgment in anysuch dispute shall be conclusive and may be enforced in other jurisdictions by suits on the judgment or in any other manner providedby law. The Parties agree that mailing of process or other papers in connection with any such action or proceeding in the mannerprovided 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 andintentionally waives any right that such Party may have to a trial by jury in any litigation based upon or arising out of thisAgreement or any related instrument or agreement, or any of the transactions contemplated thereby, or any course ofconduct, dealing, statements (whether oral or written), or actions of any of them. No Party shall seek to consolidate, bycounterclaim or otherwise, any action in which a jury trial has been waived with any other action in which a jury trial cannotbe 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, returnreceipt requested) as follows:If to the Company to:QEP Resources, Inc.1050 17th StreetDenver, CO 80265Attention: Christopher K. Woosley, Esq.Email: chris.woosley@qepres.com8with a copy (which shall not constitute notice) to:Wachtell, Lipton, Rosen & Katz51 West 52nd StreetNew York, NY 10019-6119Attention: David A. Katz, Esq.Email: dakatz@wlrk.comandLatham & Watkins LLP885 Third AvenueNew York, NY 10022-4834Attention: Mark D. Gerstein, Esq.Email: mark.gerstein@lw.comIf to Elliott:Elliott Management Corporation40 West 57 StreetNew York, NY 10019-4001Attention: Andrew TaylorEmail: ataylor@elliottmgmt.comwith a copy (which shall not constitute notice) to:Olshan Frome Wolosky LLP1325 Avenue of the AmericasNew York, NY 10019Attention: Steve Wolosky, Esq. and Andrew Freedman, Esq.Email: swolosky@olshanlaw.com and afreedman@olshanlaw.comAt any time, any Party may, by notice given in accordance with this paragraph 12 to the other Party, provide updated information fornotices hereunder13. This Agreement may be executed in two counterparts, each of which shall be deemed to be an original, but all ofwhich shall constitute the same agreement and shall become a binding agreement when a counterpart has been signed by each partyand 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 originalsignatures for all purposes and the exchange of copies of this Agreement and of signature pages by facsimile transmission, PDF orother 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. StanleyName:Charles B. StanleyTitle:Chairman, President and Chief Executive OfficerAccepted 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Exhibit 12.1QEP Resources, Inc.Ratio of Earnings to Fixed Charges Year Ended December 31, 2017 2016 2015 2014 2013Earnings(in millions)Income from continuing operations before income taxes and adjustmentfor income or loss from equity investees$(42.9) $(1,953.2) $(243.0) $(642.0) $112.2Add (deduct): Fixed charges141.0 146.2 148.3 175.6 167.8Distributed income from equity investees— — 0.1 0.3 0.2Capitalized interest— — — — (2.0)Total earnings$98.1 $(1,807.0) $(94.6) $(466.1) $278.2Fixed Charges Interest expense$137.8 $143.2 $145.6 $172.9 $163.3Capitalized interest— — — — 2.0Estimate of the interest within rental expense3.2 3.0 2.7 2.7 2.5Total Fixed Charges$141.0 $146.2 $148.3 $175.6 $167.8Ratio 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 theyear 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 forthe 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 theyear 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 theyear ended December 31, 2014, to achieve a ratio of 1:1.Exhibit 21.1QEP Resources, Inc.Subsidiaries of the CompanyNameState of OrganizationQEP Energy Company(1)DelawareQEP Marketing Company(1)UtahQEP Field Services Company(1)DelawareClear Creek Storage Company, LLC(2)UtahPermian Gathering, LLC(2)DelawareQEP Oil & Gas Company(2)DelawareWyoming Peak Land Company, LLC(3)WyomingHaynesville Gathering LP(4)DelawareSakakawea 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.Exhibit 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe 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 andNo. 333-167727) of QEP Resources, Inc. of our report dated February 28, 2018, relating to the financial statements and the effectiveness of internal controlover financial reporting, which appears in this Form 10-K./s/ PricewaterhouseCoopers LLPDenver, ColoradoFebruary 28, 2018Exhibit 23.2 FAX (303) 623-4258621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE (303) 623-9147CONSENT OF INDEPENDENT PETROLEUM ENGINEERSAs independent petroleum engineers, we hereby consent to the reference of our appraisal reports relating to the proved gas and oil reserves of QEP EnergyCompany 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 incorporatedherein 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 Exhibit 23.3DEGOLYER AND MACNAUGHTON5001 SPRING VALLEY VOADSUITE 800 EASTDALLAS, TEXAS 75244February 28, 2018QEP Resources, Inc.1050 17th Street, Suite 800Denver, Colorado 80265Ladies 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 Revenueowned 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Exhibit 24POWER OF ATTORNEYWe, the undersigned directors of QEP Resources, Inc., hereby severally constitute Charles B. Stanley and Richard J. Doleshek, and each of themacting 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, theAnnual 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., herebyratifying 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 allamendments to such Report.Witness our hands on the respective dates set forth below. Signature Title Date /s/ Charles B. Stanley Chairman of the Board 2/28/2018Charles B. Stanley President and Chief Executive Officer /s/ David A. Trice Director 2/28/2018David A. Trice /s/ Julie A. Dill Director 2/28/2018Julie A. Dill /s/ M. W. Scoggins Director 2/28/2018M. W. Scoggins /s/ Mary Shafer Malicki Director 2/28/2018Mary Shafer Malicki /s/ Michael J. Minarovic Director 2/28/2018Michael J. Minarovic /s/ Phillip S. Baker, Jr. Director 2/28/2018Phillips S. Baker, Jr. /s/ Robert F. Heinemann Director 2/28/2018Robert F. Heinemann /s/ William L. Thacker, III Director 2/28/2018William L. Thacker, III Exhibit 31.1CERTIFICATIONI, 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 thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial 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 inExchange 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 withinthose 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 oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal 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 theeffectiveness 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 mostrecent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likelyto materially affect, the registrant's internal control over financial reporting; and5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, tothe 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 arereasonably 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 internalcontrol over financial reporting.February 28, 2018/s/ Charles B. StanleyCharles B. StanleyChairman, President and Chief Executive OfficerExhibit 31.2CERTIFICATIONI, 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 thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial 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 inExchange 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 withinthose 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 oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal 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 theeffectiveness 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 mostrecent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likelyto materially affect, the registrant's internal control over financial reporting; and5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, tothe 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 arereasonably 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 internalcontrol over financial reporting.February 28, 2018/s/ Richard J. DoleshekRichard J. DoleshekExecutive Vice President and Chief Financial OfficerExhibit 32.1CERTIFICATION PURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002In 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 andExchange 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 adoptedpursuant 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QEP Energy Company January 19, 2018Page 1Exhibit 99.1 FAX (303) 623-4258621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE (303) 623-9147January 19, 2018QEP Energy Company1050 Seventeenth Street, Suite 800Denver, Colorado 80265Gentlemen:At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, andincome attributable to certain leasehold and royalty interests of QEP Energy Company (QEP) as of December 31, 2017. The subject properties arelocated in the states of Colorado, Louisiana, Montana, New Mexico, North Dakota, Oklahoma, Texas, Utah and Wyoming. The reserves andincome 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 FederalRegister (SEC regulations). Our third party study, completed on January 19, 2018 and presented herein, was prepared for public disclosure byQEP 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 thetotal 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 hydrocarbonprices. 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 ofdate” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month withinsuch period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may varysignificantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actuallyreceived 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, 2018Page 2SEC PARAMETERSEstimated Net Reserves and Income DataCertain Leasehold and Royalty Interests ofQEP Energy CompanyAs of December 31, 2017 Proved Developed TotalProved Producing Non-producing Undeveloped Net Remaining Reserves Oil/Condensate - Mbbl108,714 7,306 204,508 320,528 Plant Products - Mbbl26,374 1,500 37,371 65,245 Gas - MMcf vc523,275 132,221 1,138,150 1,793,646 Income Data ($M) Future Gross Revenue$6,849,160 $753,892 $13,309,878 $20,912,930 Deductions3,754,955 509,056 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 $3,753,836Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (Mbbl). All gas volumes are reported on an “as sold basis”expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In thisreport, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economicsoftware package ARIESTM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at therequest of QEP. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary dueto rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightlyfrom 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 thewells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. Other deductions are variablelease 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 reservesaccount 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 formas follows.QEP Energy Company January 19, 2018Page 3 Discounted Future Net Income ($M)As of December 31, 2017Discount RatePercent TotalProved5 $5,314,8829 $4,002,35315 $2,812,88720 $2,199,279The results shown above are presented for your information and should not be construed as our estimate of fair market value.Reserves Included in This ReportThe proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulations Part210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled "Petroleum Reserves Definitions" is included as anattachment to this report.The various proved reserve status categories are defined under the attachment entitled "Petroleum Reserves Status Definitions andGuidelines" in this report. The proved developed non-producing reserves included herein consist of wells that are waiting on completion, behindpipe, 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, gasconsumed in operations was excluded from reserves. However, in some cases, produced gas consumed in operations was included in reserveswhen the volumes replaced fuel purchases.Reserves are "estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of agiven date, by application of development projects to known accumulations." All reserve estimates involve an assessment of the uncertaintyrelating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the datethe estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimateand the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principalclassifications, 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 reportaddresses 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 estimatedwith reasonable certainty to be economically producible from a given date forward". The proved reserves included herein were estimated usingdeterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a "high degree ofconfidence that the quantities will be recovered."Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economicconditions change. For proved reserves, the SEC states that "as changes due to increased availability of geoscience (geological, geophysical, andgeochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is muchmore likely to increase or remain constant than to decrease." Moreover, estimates of proved reserves may be revised as a result of futureoperations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this reportare estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs relatedthereto, could be more or less than the estimated amounts.QEP Energy Company January 19, 2018Page 4QEP'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 tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices,environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change fromtime to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts ofproved income actually received to 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 liabilitiesthat 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 ReservesThe estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities ofrecoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities inaccordance with the definitions set forth by the Securities and Exchange Commission's Regulations Part 210.4-10(a). The process of estimatingthe quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analyticalprocedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. Thesemethods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserveevaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature andamount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performancecharacteristics 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 indicatea range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves isidentified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities areestimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by thereserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible thataddresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonablecertainty wherein the "quantities actually recovered are much more likely than not to be achieved." The SEC states that "probable reserves arethose additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as notto be recovered." The SEC states that "possible reserves are those additional reserves that are less certain to be recovered than probablereserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possiblereserves." All quantities of reserves within the same reserve category 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 orengineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised dueto other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies orgeopolitical 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 producingreserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include, but maynot be limited to, decline curve analysis which utilized extrapolations of historical production data available through December 2017 in those caseswhere such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by QEP and were consideredsufficient 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, 2018Page 5To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors andassumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot bemeasured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under theSEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward basedon existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it mayreasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to suchproduction may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by theSEC, 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 andother data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished byQEP 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, developmentplans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geologicalstructural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for itsreasonableness; however, we have not conducted an independent verification of the data furnished by QEP. We consider the factual data used inthis 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. Theproved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC)Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively asthe "SEC Regulations." In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosurerequirements as required by the SEC regulations.Future Production RatesFor wells currently on production, our forecasts of future production rates are based on historical performance data. If no productiondecline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until adecline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has beenestablished, 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 arenot currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by QEP. Wells orlocations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing achange 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 lessthan 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 byregulatory bodies.Hydrocarbon PricesQEP Energy Company January 19, 2018Page 6The 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 monthwithin 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 contractexpiration, 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 weredetermined using the 12-month average first-day-of-the month benchmark prices appropriate to the geographic area where the hydrocarbons aresold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the "benchmarkprices" and "price reference" used for the geographic area included in the report. In certain geographic areas, the price reference and benchmarkprices 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 benchmarkprices for gravity, quality, local conditions, and/or distance from market, referred to herein as "differentials." The differentials used in thepreparation of this 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 beforeproduction taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of thegeographic areas included in the report.Geographic AreaProductPrice ReferenceAverage BenchmarkPricesAverage Realized PricesNorth America United StatesOil/CondensateWTI Cushing$51.34/bbl$49.11/bblNGLsWTI Cushing$51.34/bbl$15.99/bblGasHenry Hub$2.98/MMBTU$2.92/McfThe effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual propertyevaluationsCostsOperating costs for the leases and wells in this report were furnished to us by QEP and are based on the operating expense reports ofQEP and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrativecosts 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 notconducted an independent verification of the operating cost data used by QEP. No deduction was made for loan repayments, interest expenses, orexploration 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 forsimilar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, wehave not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for propertieswhere abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by QEP were accepted withoutindependent verification.QEP Energy Company January 19, 2018Page 7The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with QEP'splans to develop these reserves as of December 31, 2017. The implementation of QEP's development plans as presented to us and incorporatedherein 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 byQEP's management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain developmentactivities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvalsexternal to QEP. Additionally, QEP has informed us that they are not aware of any legal, regulatory or political obstacles that would significantlyalter their plans. While these plans could change from those under existing economic conditions as of December 31, 2017, such changes were, inaccordance with rules adopted by the SEC, 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 QualificationRyder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout theworld since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. Wehave 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 weprovide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of anyprivately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-makingprocess 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 ofreserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves relatedtopics. 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 professionalaccreditation in the form of a registered or certified professional engineer's license or a registered or certified professional geoscientist's license, orthe 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 thesubject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the propertieswhich were reviewed.The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers fromRyder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of thereserves information discussed in this report, are included as an attachment to this letter.Terms of UsageThe results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forthin 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 registrationstatements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We haveconsented 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 wellas to the references to our third party report for QEP, which appears in the December 31, 2017 annual report on Form 10-K of QEP. Our writtenconsent for such use is included as a separate exhibit to the filings made with the SEC by QEP.QEP Energy Company January 19, 2018Page 8We have provided QEP with a digital version of the original signed copy of this report letter. In the event there are any differences betweenthe digital version included in filings made by QEP and the original signed report letter, the original signed report letter shall control and supersedethe digital version.QEP Energy Company January 19, 2018Page 9The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Pleasecontact 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. BairdJames L. Baird, P.E.Colorado License No 41521Managing Senior Vice President[Seal]/s/ Richard J. MarshallRichard J. Marshall, P.E.Colorado License No. 23260Vice President[Seal]JLB-RJM (DCR)/plQEP Energy Company January 19, 2018Page 10Professional Qualifications of Primary Technical PersonThe conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder ScottCompany, L.P. Richard J. Marshall was the primary technical person responsible for overseeing the estimate of the future net reserves andincome.Mr. Marshall, an employee of Ryder Scott Company, L.P. (Ryder Scott) beginning in 1981, is a Vice President responsible for coordinating andsupervising staff and consulting engineers of the company in ongoing reservoir evaluation studies. Before joining Ryder Scott, Mr. Marshall servedin a number of engineering positions with Texaco, Phillips Petroleum, and others. For more information regarding Mr. Marshall's geographic and jobspecific 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 ofMissouri at Rolla in 1976. Mr. Marshall is a registered Professional Engineer in the State of Colorado. He is a member of the Society of PetroleumEngineers, 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 andevaluation of petroleum reserves, Mr. Marshall has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as setforth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society ofPetroleum Engineers as of February 19, 2007.

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