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•	our growth strategies;

•	strong liquidity position providing financial flexibility;

•	our liquidity and sufficiency of cash flow from operations, cash on hand and, if needed, availability under our revolving credit facility to fund our operations and planned capital expenditures;

•	plans and ability to pursue acquisition opportunities;

•	our inventory of drilling locations;

•	drilling and completion plans and strategies;

•	results from planned drilling operations and production operations;

•	plans to increase oil and gas production;

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

•	payments of dividends;

•	estimates of reserves;

•	future development costs;

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

•	leasehold development and financial capability to continue planned development;

•	ability to incur additional indebtedness under our revolving credit facility;

•	loss contingencies;

•	sufficiency of accruals;

•	expectations regarding oil, gas and NGL prices;

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

•	pro forma results for acquired properties;

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

•	the unfunded status of our pension plan;

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

•	impact of global geopolitical and macroeconomic events;

•	plans to enter into derivative contracts and the anticipated benefits from our derivative contracts;

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•	divestitures of assets;

•	trucking of products to sales points;

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

•	need for capital expenditures to address air emission issues;

•	amount and allocation of forecasted capital expenditures and plans for funding capital expenditures, operating expenses and working capital requirements;

•	adequacy of insurance;

•	impact of and compliance with government regulations;

•	assumptions regarding equity compensation;

•	settlement of performance share units in cash;

•	recognition of compensation costs related to equity compensation grants;

•	expected contributions to our employee benefit plans;

•	employee benefit plan gains or losses;

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

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

•	fair values and critical accounting estimates, including estimated asset retirement obligations;

•	uncertain tax positions;

•	unrecognized tax benefits and the realization of those benefits;

•	implementation and impact of new accounting pronouncements;

•	impact of shutting in wells;

•	factors impacting our ability to transport oil and gas;

•	potential for asset impairments and impact of impairments on financial statements;

•	no expected additional costs of restructurings;

•	managing counterparty risk exposure;

•	loss of customers;

•	outcome and impact of various claims;

•	ability to meet delivery and sales commitments;

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

•	inflation and deflation; and

•	value of pension plan assets and plans regarding additional contributions to the pension plan.

•	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;

•	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;

•	shortages of oilfield equipment, services and personnel;

•	lack of available pipeline, processing and refining capacity;

•	processing volumes and pipeline throughput;

•	our ability to successfully integrate acquired assets;

•	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

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•	derivative activities;

•	potential financial 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;

•	estimates of oil and gas reserve quantities;

•	reservoir performance;

•	operating costs;

•	inflation;

•	capital costs;

•	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; and

•	other factors, most of which are beyond the Company’s control.

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•	Reported record oil equivalent reserves of 731.4 MMboe as of December 31, 2016, a 21% increase over 2015;

•	Delivered record oil equivalent production of 55.8 MMboe, a 2% increase over 2015;

•	Increased oil production to 20.3 MMbbl, a 4% increase over 2015, including a 43% increase in the Permian Basin;

•	Reduced lease operating and transportation and other handling expense by $0.52 per Boe compared to the year ended December 31, 2015, to $9.21 per Boe;

•	Generated a net loss of $1,245.0 million, or $5.62 per diluted share;

•	Reported $626.2 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);

•	Incurred capital expenditures (excluding property acquisitions) of $530.1 million, a 48% reduction from 2015;

•	Incurred impairment expense of $1,194.3 million, primarily due to lower future commodity prices;

•	Issued 60.95 million shares of common stock through two public offerings and received net proceeds of approximately $781.4 million;

•	Acquired various oil and gas properties for approximately $645.2 million, of which approximately $590.6 million was related to the 2016 Permian Basin Acquisition (defined below), subject to customary purchase price adjustments; and

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•	Maintained strong liquidity, including $443.8 million in cash and cash equivalents and no borrowings under its revolving credit facility as of December 31, 2016.

•	operate in a safe and environmentally responsible manner;

•	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;

•	divest of non-core assets;

•	maintain an inventory of low-cost, high-margin development projects in resource plays;

•	develop the highest-potential areas of the resource plays in which we operate;

•	build contiguous acreage positions that drive operating efficiencies;

•	be the operator of our assets, whenever possible;

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

•	actively market our production to maximize value;

•	utilize derivative contracts to 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.

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(1)	Proved reserves include gas reserves that QEP expects to produce and use as field fuel.

(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.

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

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(1)

Revisions of previous estimates include 51.1 MMboe of positive revisions, primarily related to reserves associated with increased density wells in areas that have been previously developed on lower density spacing and 3.4 MMboe of positive performance revisions. These positive revisions were partially offset by 3.8 MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices.

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

(3)	Purchase of reserves in place in 2016 was primarily related to the 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K.

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

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(1)	Gross productive wells includes 69 wells in which QEP only owns a small overriding royalty interest.

(1)	Developed acreage is leased acreage assigned to productive wells.

(2)	Undeveloped acreage is leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

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

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

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

•	localized supply and demand fundamentals, including the proximity, cost and availability of pipelines and other transportation facilities, and other factors that result in differentials to benchmark prices from time to time;

•	the availability of refining and storage capacity;

•	domestic and global economic and political conditions;

•	speculative trading in crude oil and natural gas derivative contracts;

•	the continued threat of terrorism and the impact of military and other action;

•	the activities of the Organization of Petroleum Exporting Countries (OPEC) and other oil producing countries, including the ability of members of OPEC to maintain oil price and production controls;

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

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

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•	weather conditions and natural disasters;

•	government laws, regulations and taxes, including regulations or legislation relating to climate change, induced seismicity or oil and gas exploration and production activities;

•	technological advances affecting energy consumption and energy supply;

•	conservation efforts;

•	the price, availability and acceptance of alternative fuels, including coal, nuclear energy 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.

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

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

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

•	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; and

•	decreasing the value of QEP's common stock.

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•	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;

•	title problems;

•	equipment malfunctions and/or mechanical failure;

•	security breaches, cyber attacks, piracy, or terrorist acts;

•	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; and

•	environmental accidents such as oil spills, natural gas leaks, pipeline or tank ruptures, or discharges of air pollutants, brine water or well fluids into the environment.

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•	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.

•	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.

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•	delay or denial of drilling and other necessary permits;

•	shortening of lease terms or reduction in lease size;

•	restrictions on installation or operation of production or gathering facilities;

•	more stringent setback requirements from houses, schools and businesses;

•	towns, cities, states and counties considering bans on certain activities, including hydraulic fracturing;

•	restrictions on the use of certain operating practices, such as hydraulic fracturing, or the disposition of related waste materials, such as hydraulic fracturing fluids and produced water;

•	reduced access to water supplies;

•	increased severance and/or other taxes;

•	cyber attacks;

•	legal challenges or lawsuits;

•	negative publicity about QEP;

•	disinvestment 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; and

•	postponement of federal and state oil and gas lease sales.

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•	large multi-national, integrated oil companies;

•	U.S. independent oil and gas companies;

•	service companies engaging in oil and gas exploration and production activities; and

•	private equity funds investing in oil and gas assets.

•	acquiring desirable producing properties or new leases for future exploration;

•	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.

•	difficulty integrating the operations, systems, management and other personnel and technology of the acquired business or assets with QEP's own;

•	the assumption of unidentified or unforeseeable liabilities, resulting in a loss of value;

•	the inability to hire, train or retain qualified personnel to manage and operate QEP's growing business and assets; or

•	a decrease in QEP's liquidity to the extent it uses a significant portion of its available cash or borrowing capacity to finance acquisitions or operations of the acquired properties.

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

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

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

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•	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, 2011, and its relative performance is tracked through December 31, 2016;

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

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

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(1)	All of the shares purchased during the three-month period ended December 31, 2016, were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting of restricted stock grants.

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

(2)

During the years ended December 31, 2016, 2015 and 2014, the results are impacted by the 2014 Permian Basin Acquisition, which occurred in February 2014, and the property sales in the Other Southern area, beginning in the second quarter of 2014. See Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K for detailed information on the 2014 Permian Basin Acquisition and property divestitures.

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(3)

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

(4)	In December 2014, QEP sold substantially all of QEP's midstream business. The results of operations of QEP's midstream business (excluding results of Haynesville Gathering) have been reflected as discontinued operations and results for the years ended December 31, 2014, 2013 and 2012, have been reclassified.

(5)

Adjusted EBITDA is a non-GAAP financial measure. Management defines Adjusted EBITDA as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA), adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment and certain other items. See Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report on Form 10-K for additional disclosures related to Adjusted EBITDA.

(1)

Reflects legal expenses and loss contingencies incurred during the year ended December 31, 2016, a non-cash pension curtailment loss incurred during the year ended December 31, 2015, a loss from early extinguishment of debt incurred during the year ended December 31, 2014, and a loss from early extinguishment of debt and legal expenses related to class action lawsuit incurred during the year ended December 31, 2012. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA.

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•	Reported record oil equivalent reserves of 731.4 MMboe as of December 31, 2016, a 21% increase over 2015;

•	Delivered record oil equivalent production of 55.8 MMboe, a 2% increase over 2015;

•	Increased oil production to 20.3 MMbbl, a 4% increase over 2015, including a 43% increase in the Permian Basin;

•	Reduced lease operating and transportation and other handling expense by $0.52 per Boe compared to the year ended December 31, 2015, to $9.21 per Boe;

•	Generated a net loss of $1,245.0 million, or $5.62 per diluted share;

•	Reported $626.2 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);

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•	Incurred capital expenditures (excluding property acquisitions) of $530.1 million, a 48% reduction from 2015;

•	Incurred impairment expense of $1,194.3 million, primarily due to lower future commodity prices;

•	Issued 60.95 million shares of common stock through two public offerings and received net proceeds of approximately $781.4 million;

•	Acquired various oil and gas properties for approximately $645.2 million, of which approximately $590.6 million was related to the 2016 Permian Basin Acquisition, subject to customary purchase price adjustments; and

•	Maintained strong liquidity, including $443.8 million in cash and cash equivalents and no borrowings under its revolving credit facility as of December 31, 2016.

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(1)

Reflects legal expenses and loss contingencies incurred during the year ended December 31, 2016, a non-cash pension curtailment loss incurred during the year ended December 31, 2015, and a loss from early extinguishment of debt incurred during the year ended December 31, 2014. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA.

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(1)	The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the years ended December 31, 2016 and 2015, as compared to the years ended December 31, 2015 and 2014, by the average field-level price for the years ended December 31, 2015 and 2014.

(2)

The revenue variance attributed to the change in price is calculated by multiplying the change in field-level prices from the years ended December 31, 2016 and 2015, as compared to the years ended December 31, 2015 and 2014, by the respective volumes for the years ended December 31, 2016 and 2015. Pricing changes are driven by changes in commodity field-level prices, excluding the impact from commodity derivatives.

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•	$134.0 million 6.80% Senior Notes due April 2018;

•	$136.0 million 6.80% Senior Notes due March 2020;

•	$625.0 million 6.875% Senior Notes due March 2021;

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

•	$650.0 million 5.25% Senior Notes due May 2023.

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(1)	This table excludes the Company's benefit plan liabilities as future payment dates are unknown. See Note 12 – Employee Benefits, in Item 8 of Part II of this Annual Report on Form 10-K for additional information.

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

(3)	These future obligations are discounted estimates of future expenditures based on expected settlement dates. See Note 5 – Asset Retirement Obligations, in Item 8 of Part II in this Annual Report on Form 10-K for additional information.

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(1)	Presented net of income tax benefit of $0.3 million for the year ended December 31, 2015.

(2)	Presented net of income tax benefit of $3.3 million, $0.3 million and $8.5 million for the years ended December 31, 2016, 2015 and 2014, respectively.

(3)	Presented net of income tax expense of $0.5 million, $4.9 million, and $6.0 million during the years ended December 31, 2016, 2015, and 2014, respectively.

(4)	Presented net of income tax expense of $0.3 million, $0.2 million, and $0.3 million during the years ended December 31, 2016, 2015, and 2014, respectively.

(5)	Presented net of income tax expense of $2.6 million and $3.5 million for the years ended December 31, 2015 and 2014, respectively.

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(1)	Includes discontinued intercompany eliminations.

(2)	Includes income from discontinued operations before income taxes attributable to QEP from QEP Midstream (of which QEP owned 57.8%) of $28.9 million for the year ended December 31, 2014.

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

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(1)	The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Consolidated Balance Sheets for the contracts that contain netting provisions. See Note 7 – Derivative Contracts for additional information regarding the Company's derivative contracts.

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(1)	During the year ended December 31, 2016, the Company paid $176.8 million for the repayment of the 6.05% Senior Notes, which were due on September 1, 2016.

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

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

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(1)	Reflects legal expenses and loss contingencies incurred during the year ended December 31, 2016, and a non-cash pension curtailment incurred during the year ended December 31, 2015.

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(1)

Revisions of previous estimates in 2014 include 41.4 MMboe negative performance revisions partially offset by positive other revisions of 33.0 MMboe, operating cost revisions of 6.5 MMboe and pricing revisions of 3.8 MMboe. Negative performance revisions were driven by a 32.3 MMboe decrease in Pinedale reserves related to downward forecast revisions on proved developed (PDP) wells, additional production history on PUD to PDP performance and a downward adjustment in the number of PUD locations. Other negative revisions related to adjustments to shrink and lease operating expense. Pricing revisions were primarily due to increased gas prices, which increased reserves by 3.7 MMboe.

(2)	Extensions and discoveries in 2014 increased proved reserves by 49.0 MMboe, primarily related to extensions and discoveries in Pinedale of 22.3 MMboe and the Williston Basin of 20.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations as well as new compression well projections in Pinedale.

(3)	Purchase of reserves in place in 2014 relate to the Company's 2014 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.

(4)	Sale of reserves in place primarily related to property sales in the Other Southern area in the second and fourth quarters of 2014 as discussed in Note 2 – Acquisitions and Divestitures.

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

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

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

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

(9)

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

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

(11)	Purchase of reserves in place in 2016 relate primarily to the Company's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures.

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

(13)	Proved reserves include gas reserves that QEP expects to produce and use as field fuel.

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

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

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

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

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

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*	Filed herewith

**	These interactive data files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.

+	Indicates a management contract or compensatory plan or arrangement

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1.

Grant of Performance Share Units. Subject to the terms and conditions of this Agreement and the Company’s Cash Incentive Plan (the “Plan”), the Company hereby issues to Grantee the right to receive a number of Performance Share Units calculated in the manner set forth in Appendix A hereto, based on the achievement of one or more Performance Goals that must be attained over a relevant Performance Period, and assuming a target award of ______________ Performance Share Units (the “Target Share Units”). Each Performance Share Unit actually earned and vested in accordance with this Agreement and Appendix A hereto represents the right to receive a cash payment equal to the Fair Market Value of one share of the Company’s no par value common stock (“Common Stock”), subject to Section 3 and the other terms and conditions of this Agreement. Terms not defined herein shall have the meanings ascribed to them in the Plan.

2.	Vesting; Termination of Employment; Forfeiture.

a)	Termination of Employment. Except as provided in subsections (b) and (c) below, if the Grantee terminates employment with the Company and its Affiliates for any reason prior to the Vest Date, the Grantee shall forfeit any and all interest under this Agreement and shall forfeit the right to receive any Performance Share Units hereunder.

b)

Death, Disability, or Retirement. If the Grantee terminates employment with the Company and its Affiliates on account of death, Disability, or Retirement (as defined below) prior to the last day of the Performance Period, the Grantee shall receive on the Vest Date a pro rata portion of the Performance Share Units that would otherwise have been received for the Performance Period, subject to certification by the Committee, in an amount equal to the product of (x) the number of Performance Share Units that would have been earned in accordance with the provisions of Appendix A had Grantee remained in the continuous employment of the Company or its Affiliates through the last day of the Performance Period, multiplied by (y) the ratio between (i) the number of full months of employment completed from the first day of the Performance Period to the date of termination of employment and (ii) the number of full months in the Performance Period. If the Grantee terminates employment with the Company and its Affiliates on account of death, Disability, or Retirement on or after the last day of the Performance Period but before the Vest Date, the Grantee shall receive on the Vest Date the Performance Share Units that would have been earned in accordance with the provisions of Appendix A had the Grantee remained in the continuous employment of the Company or its Affiliates through the Vest Date. “Retirement” shall mean Grantee’s voluntary termination of employment with the Company and its Affiliates on or after age 55 with at least 10 years of service; provided that such retirement occurs no earlier than 12 months after the first day of the Performance Period, or such other retirement as shall be approved by the Committee in its discretion.

c)

Termination Following a Change in Control. If, upon a Change in Control of the Company or within the three years thereafter, the Grantee’s employment is terminated prior to the Vest Date (i) by the Company and its Affiliates for any reason other than Cause (as defined below) or Disability (it being understood that upon termination for Disability, the provisions of paragraph (b) above shall apply) or (ii) by the Grantee for Good Reason (as defined below) within 60 days following the expiration of the cure period afforded the Company to rectify the condition giving rise to Good Reason, the Grantee shall be entitled to receive a payment for the Performance Share Units earned hereunder based on the greater of (A) the level of achievement of the applicable performance goals as of immediately prior to the Change in Control or (B) the level of achievement of the applicable performance goals as of the date of termination of employment (which for

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i.

“Cause” means the Grantee’s: (i) willful and continued failure to perform substantially the Grantee’s duties with an Employer (other than any such failure resulting from incapacity due to physical or mental illness), following written demand for substantial performance delivered to the Grantee by the Board or the Chief Executive Officer of the Company; or (ii) willful engagement in conduct that is materially injurious to an Employer. For purposes of this definition, no act or failure to act on the part of the Grantee shall be considered “willful” unless it is done, or omitted to be done, by the Grantee without reasonable belief that the Grantee’s action or omission was in the best interests of the Grantee’s Employer. The Company, acting through the Board, must notify the Grantee in writing that the Grantee’s employment is being terminated for “Cause”. The notice shall include a list of the factual findings used to sustain the judgment that the Grantee’s employment is being terminated for “Cause”.

ii.

“Good Reason” means any of the following events or conditions that occur without the Grantee’s written consent, and that remain in effect after notice has been provided by the Grantee to the Company of such event or condition and the expiration of a 30 day cure period: (i) a material diminution in the Grantee’s gross annual base salary (as in effect immediately prior to the Change in Control of the Company), target incentive opportunity under any Annual Cash Incentive Plan or long-term incentive award opportunity under any Long-Term Incentive Plan or Stock Incentive Plan; (ii) a material diminution in the Grantee’s authority, duties, or responsibilities; (iii) a material diminution in the authority, duties, or responsibilities of the supervisor to whom the Grantee is required to report, including a requirement that the Grantee report to a corporate officer or employee instead of reporting directly to the Board; (iv) a material diminution in the budget over which the Grantee retains authority; (v) a material change in the geographic location at which the Grantee performs services; or (vi) any other action or inaction that constitutes a material breach by an Employer of the Grantee’s employment agreement (if any). The Grantee’s notification to the Company must be in writing and must occur within a reasonable period of time, not to exceed 90 days, following the initial existence of the relevant event or condition. For purposes of this definition:

A.	“Annual Cash Incentive Plan” means any annual incentive plan, program or arrangement offered by an Employer pursuant to which the Grantee is eligible to receive a cash award, subject in whole or in part to the achievement of performance goals over a period of no more than one year, including without limitation the Plan.

B.	“Long-Term Incentive Plan” means any long-term incentive plan, program or arrangement offered by an Employer pursuant to which the Grantee is eligible to receive an award, subject in whole or in part to the achievement of performance goals over a period of more than one year, including without limitation the Plan.

C.	“Stock Incentive Plan” means any incentive plan offered by the Company pursuant to which upon or following vesting or exercise, as applicable, the Grantee is entitled to receive shares of the Company’s Common Stock, including without limitation the QEP Resources, Inc. 2010 Long-Term Stock Incentive Plan.

3.	Payment.

a)

General. As soon as practicable after the end of the Performance Period the Committee shall determine and certify the number of Performance Share Units that have been earned in accordance with Appendix A and the terms and conditions of this Agreement. Subject to subsection (b), payment for Performance Share Units shall be made in cash on the Vest Date. The amount distributable shall be based on the average closing Company stock price for the fourth quarter of the final year of the Performance Period. All payments shall be made as soon as administratively practicable after the date on which the Committee determines and certifies the number of Performance Share Units that have been earned, but in all events not later than March 15 of the calendar year following the calendar year in which the Performance Period ends. The foregoing provisions

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b)

Payment in Shares. Notwithstanding anything in the Plan, this Agreement or in Appendix A to the contrary, in lieu of paying the Performance Share Units in cash as provided in subsection (a), the Committee may elect in its discretion to pay some or all of the Performance Share Units in the form of an equal number of actual shares of the Company’s (or its successor’s) Common Stock or other applicable securities, which shares of Common Stock or other applicable securities shall be delivered to the Grantee under the Company’s 2010 Long-Term Stock Incentive Plan (as it may be amended or restated from time to time, or, to the extent applicable, any future or successor equity compensation plan of the Company).

4.	No Rights of a Stockholder. The Grantee shall have no voting or other rights as a stockholder of the Company with respect to this award. The Grantee’s right to receive payments earned under this Agreement shall be no greater than the right of any unsecured general creditor of the Company.

5.

Adjustments to Performance Share Units. In the event of any stock dividend, extraordinary cash dividend, recapitalization, reorganization, merger, consolidation, split-up, spin-off, combination, exchange of shares, grant of warrants or rights offering to purchase Common Stock at a price materially below fair market value or other similar corporate event affecting the Common Stock, the Committee shall adjust the award issued hereunder in order to preserve the benefits or potential benefits intended to be made available under this Agreement. All adjustments shall be made in the sole and exclusive discretion of the Committee, whose determination shall be final, binding and conclusive. Notice of any adjustment shall be given to Grantee.

6.

Notices. Any notice required or permitted to be given under this Agreement shall be in writing and shall be given by e-mail, hand delivery or by first class registered or certified mail, postage prepaid, addressed, if to the Company, to its Corporate Secretary, and if to Grantee, to his or her address now on file with the Company, or to such other address as either may designate in writing. Any notice shall be deemed to be duly given as of the date delivered in the case of e-mail or personal delivery, or as of the second day after enclosed in a properly sealed envelope and deposited, postage prepaid, in a United States post office, in the case of mailed notice.

7.

Amendment. Except as provided herein, this Agreement may not be amended or otherwise modified unless evidenced in writing and signed by the Company and Grantee, or as approved by the Committee or its delegate. Notwithstanding any provision in this Agreement to the contrary, including Section 8, an amendment to the Plan that would materially and adversely affect Grantee’s rights with respect to the award of Performance Share Units granted hereunder will not be effective with respect to such award.

8.

Relationship to Plan. Except to the extent this Agreement provides for the discretionary stock settlement of the Target Share Units, this Agreement shall not alter the terms of the Plan. If there is a conflict between the terms of the Plan and the terms of this Agreement, the terms of the Plan shall prevail, provided, however, that the terms of Section 3(b) of this Agreement shall control over any contrary provision of the Plan. Capitalized terms used in this Agreement but not defined herein shall have the meaning given such terms in the Plan.

9.

Construction; Severability. The section headings contained herein are for reference purposes only and shall not in any way affect the meaning or interpretation of this Agreement. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, and each other provision of this Agreement shall be severable and enforceable to the extent permitted by law.

10.	Waiver. Any provision contained in this Agreement may be waived, either generally or in any particular instance, by the Committee appointed under the Plan, but only to the extent permitted under the Plan.

11.

Entire Agreement; Binding Effect. Once accepted, this Agreement, the terms and conditions of the Plan, and the award of Performance Share Units set forth herein, constitute the entire agreement between Grantee and the Company governing such award of Performance Share Units, and shall be binding upon and inure to the benefit of the Company and to Grantee and to the Company’s and Grantee’s respective heirs, executors, administrators, legal representatives, successors and assigns.

12.	No Rights to Employment. Nothing contained in this Agreement shall be construed as giving Grantee any right to be retained in the employ of the Company or its Affiliates and this Agreement is limited solely to governing the rights and obligations of Grantee with respect to the Performance Share Units.

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13.	Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Delaware, without regard to the choice of law principles thereof.

14.	Section 409A. For the avoidance of doubt, the provisions of Section 7(g) of the Plan shall apply to this Agreement and all payments made or to be made in connection with this Agreement.

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(1)	Due to a loss for the year ended December 31, 2016, the ratio coverage was less than 1:1. QEP required additional earnings of $1,953.2 million for the year ended December 31, 2016, to achieve a ratio of 1:1.

(2)	Due to a loss for the year ended December 31, 2015, the ratio coverage was less than 1:1. QEP required additional earnings of $243.0 million for the year ended December 31, 2015, to achieve a ratio of 1:1.

(3)	Due to a loss for the year ended December 31, 2014, the ratio coverage was less than 1:1. QEP required additional earnings of $642.0 million for the year ended December 31, 2014, to achieve a ratio of 1:1.

1.	I have reviewed this report of QEP Resources, Inc. on Form 10-K for the period ended December 31, 2016;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

1.	I have reviewed this report of QEP Resources, Inc. on Form 10-K for the period ended December 31, 2016;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

(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.

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