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•	our growth strategies;

•	strong liquidity position providing financial flexibility;

•	geographical diversity;

•	our liquidity and sufficiency of cash flow from operations, cash-on-hand and availability under our credit facility to fund our planned capital expenditures, operating expenses, repayment of maturing debt and payment of dividends;

•	ability to deliver growth by focusing on our exploration and production assets;

•	our continued evaluation of, and ability to pursue, acquisition opportunities;

•	our inventory of drilling locations;

•	drilling and completion plans;

•	focus on improving operating performance by optimizing reservoir development, enhancing well completion designs and aggressively pursuing cost reductions;

•	results from planned drilling operations and production operations;

•	plans to reduce drilling and completion activities, slow production growth and preserve liquidity;

•	exports of oil from the U.S.;

•	payment of dividends;

•	estimates of reserves and development of proved undeveloped (PUD) reserves;

•	leasehold development and financial capability to continue planned development;

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

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

•	volatility of gas, oil 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;

•	pro forma results for acquired properties;

•	divestitures of non-core assets;

•	any potential repurchases of our senior notes;

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•	amount and allocation of forecasted capital expenditures and plans for funding capital expenditures, operating expenses and development costs;

•	resale revenues and expenses;

•	adequacy of insurance;

•	timing and impact of proposed environmental legislation and studies;

•	impact of governmental 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 importance of Adjusted EBITDA (a non-GAAP financial measure) as a measure of performance;

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

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

•	uncertain tax 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;

•	impact of the sale of our midstream business;

•	the estimated costs of closing our Tulsa office;

•	the impact of the loss of a significant customer or nonpayment of a counterparty;

•	ability to meet delivery and sales commitments;

•	value of pension plan assets;

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

•	inflation and deflation;

•	unrecognized tax benefits;

•	asset retirement obligations; and

•	changes to production plans, operating costs and capital expenditures.

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

•	changes in gas, oil 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 methods and results;

•	shortages of oilfield equipment, services and personnel;

•	lack of available pipeline, processing and refining capacity;

•	our ability to successfully integrate acquired assets;

•	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 laws or regulations;

•	legislation regarding climate change and other initiatives related to drilling and completion techniques, including hydraulic fracturing and water use;

•	derivative activities;

•	volatility in the commodity-futures market;

•	failure of internal controls and procedures;

•	failure of our information technology infrastructure or applications;

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

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•	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 volumes;

•	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

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

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•	Achieved record equivalent production of 326.8 Bcfe, a 1% increase over 2014;

•	Increased oil production to 19.6 MMbbls, a 14% increase over 2014, including 76% growth in the Permian Basin and 13% growth in the Williston Basin;

•	Increased natural gas production to 181.1 Bcf, including record production in Pinedale;

•	Generated a net loss of $149.4 million, or $0.85 per diluted share;

•	Generated $1,029.3 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), of which $1,027.1 million was contributed by QEP Energy;

•	Incurred capital expenditures (excluding property acquisitions) of $1,011.9 million, a 41% reduction from 2014;

•	Reduced general and administrative expenses by $23.3 million, or 11%;

•	Received field-level prices that were 42% lower than in 2014, however, our commodity derivative contracts offset 19% of this decrease; and

•	Maintained $376.1 million in cash and cash equivalents and had no borrowings under our revolving credit facility.

•	operate in a safe and environmentally responsible manner;

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

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

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•	maintain a sustainable, diverse inventory of low-cost, high-margin 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 mitigate the impact of gas, oil or NGL price volatility and to lock in acceptable cash flows required to support future capital expenditures;

•	attract and retain the best people; and

•	maintain a capital structure that provides us the necessary financial flexibility with which to invest in organic growth and potential acquisition opportunities, as they may arise.

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

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

•	changes in local, regional, national and global demand for gas, oil, NGL and related commodities;

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

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

•	the availability of refining and storage capacity;

•	domestic and global economic conditions;

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

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

•	the activities of the Organization of Petroleum Exporting Countries (OPEC), including the ability of members of OPEC to agree to and maintain oil price and production controls and the ability of Iran to market its oil following the lifting of trade sanctions;

•	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;

•	weather conditions and natural disasters;

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

•	technological advances affecting energy consumption and energy supply;

•	conservation efforts;

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

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

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

•	the quality of oil and gas produced.

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

•	fire, explosions and blowouts;

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•	aging infrastructure and mechanical problems;

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

•	pipe, cement or casing failures;

•	title problems;

•	equipment malfunctions and/or mechanical failure;

•	security breaches, cyberattacks, piracy, or 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; 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.

•	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;

•	cyberattacks;

•	legal challenges or lawsuits;

•	negative publicity about QEP;

•	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.

•	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.

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

•	marketing its gas, oil and NGL production;

•	obtaining the equipment and expertise necessary to operate and develop properties; and

•	attracting and retaining employees with certain critical skills.

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

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

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

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

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

(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 in 2015 include: 514.2 Bcfe of negative revisions due to lower pricing and 303.7 Bcfe of negative revisions unrelated to pricing, partially offset by 39.0 Bcfe of positive performance revisions. Negative pricing revisions were driven by lower gas, oil and NGL prices. Negative other revisions were primarily the result of slowing the pace of planned drilling activity and operating in ethane rejection in Pinedale and the Uinta Basin.

(2)	The increase in reserves due to extensions and discoveries in 2015 was comprised of 325.8 Bcfe in the Williston Basin, 300.6 Bcfe in the Uinta Basin, 242.1 Bcfe in the Permian Basin, 45.9 Bcfe in Pinedale, and 31.0 Bcfe in Haynesville/Cotton Valley. Extensions and discoveries relate to new PUD locations driven by drilling activity in 2015, as well as new compression projections in Pinedale.

(3)	Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP's operated wells in the Williston Basin as discussed in Note 2 – Acquisitions and Divestitures, in Item 8 of Part II of this Annual Report on Form 10-K.

(4)

All of QEP Energy's PUD reserves at December 31, 2015, are scheduled to be developed within five years from the date such locations were initially disclosed as PUD reserves; however, long-term development of gas reserves in Pinedale is governed by the BLM's September 2008 ROD on the FSEIS. Under the ROD, QEP Energy is allowed to drill and complete wells year-round in designated concentrated development areas. The ROD contains additional requirements and restrictions on the sequence of development, which requires the Company to develop its leasehold from the south to the north. These restrictions result in protracted, phased development that is beyond the control of the Company. The Company has an ongoing development plan and the financial capability to continue development in the manner estimated. Additionally, QEP Energy plans to develop its PUD reserves prior to lease expiration or extend the term of the lease.

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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.

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(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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(1)	Gross completions includes eight wells for the year ended December 31, 2015, in which QEP only owns a small overriding royalty interest.

(2)	Operated completions include eight gross, 7.4 net, vertical wells for the year ended December 31, 2015.

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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 July 1, 2010, which is the date when QEP's common stock began trading on the NYSE;

•	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 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, 2015, 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 years ended December 31, 2015, 2014, 2013 and 2012, the results are impacted by the Company's acquisition of oil and gas properties in the Williston Basin for an aggregate purchase price of $1.4 billion, which occurred on September 27, 2012.

(2)

During the years ended December 31, 2015 and 2014, the results are impacted by the Permian Basin Acquisition, which occurred on February 25, 2014, and the property sales in the Midcontinent, which occurred during the second and fourth quarters 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 Permian Basin Acquisition and property divestitures.

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(3)

Revenue for the year ended December 31, 2011, reflects the impact of QEP's settled derivative contracts, which during the years ended December 31, 2015, 2014, 2013 and 2012, is reflected below operating income (loss). See Note 7 – Derivative Contracts, in Item 8 of Part II of this Annual Report on Form 10-K for detailed information on derivative contract settlements in the years ended December 31, 2015, 2014 and 2013.

(4)

In the fourth quarter of 2015, the Company determined that certain purchased oil transactions that were included in "Revenues" on a gross basis for the year ended December 31, 2014, should have been reported net, as the transactions were with the same counterparty and were entered into in contemplation of one another. See Note 1 – Summary of Significant Accounting Policies in Item 8 of Part II of this Annual Report on Form 10-K for additional information. The Company has recast its revenues for the year ended December 31, 2014, to conform to the presentation for the year ended December 31, 2015.

(5)	In December 2014, QEP completed the Midstream Sale. QEP Field Services' financial results (excluding results of the Haynesville gathering system) have been reflected as discontinued operations and all prior periods have been reclassified.

(6)

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 non-cash and/or non-recurring items. Management focuses on Adjusted EBITDA to assess the Company's operating results. Management believes Adjusted EBITDA is an important measure for comparing the Company's financial performance to other oil and gas producing companies. Because not all companies use identical calculations, our presentation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

(1)

The pension curtailment was a non-cash expense incurred during the year ended December 31, 2015, due to changes in the Company's pension plan (see Note 12 – Employee Benefits in Item 8 of Part II of this Annual Report on Form 10-K for additional information). The Company believes that the pension curtailment does not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded the loss from the calculation of Adjusted EBITDA.

(2)	See Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, for a reconciliation of Adjusted EBITDA from discontinued operations to Net Income attributable to QEP from discontinued operations.

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•	Achieved record equivalent production of 326.8 Bcfe, a 1% increase over 2014;

•	Increased oil production to 19.6 MMbbls, a 14% increase over 2014, including 76% growth in the Permian Basin and 13% growth in the Williston Basin;

•	Increased natural gas production to 181.1 Bcf, including record production in Pinedale;

•	Generated a net loss of $149.4 million, or $0.85 per diluted share;

•	Generated $1,029.3 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), of which $1,027.1 million was contributed by QEP Energy;

•	Incurred capital expenditures (excluding property acquisitions) of $1,011.9 million, a 41% reduction from 2014;

•	Reduced general and administrative expenses by $23.3 million, or 11%;

•	Received field-level prices that were 42% lower than in 2014, however, our commodity derivative contracts offset 19% of this decrease; and

•	Maintained $376.1 million in cash and cash equivalents and had no borrowings under our revolving credit facility.

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(1)	Includes intercompany eliminations.

(2)

The pension curtailment was a non-cash expense incurred during the year ended December 31, 2015, due to changes in the Company's pension plan (see Note 12 – Employee Benefits, in Item 8 of Part II of this Annual Report on Form 10-K for additional information). The Company believes that the pension curtailment does not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded the loss from the calculation of QEP's Adjusted EBITDA.

(3)	Excludes noncontrolling interest's share of $1.5 million and $0.4 million during the years ended December 31, 2014, and 2013, respectively, of interest expense attributable to QEP Midstream.

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(4)	Excludes noncontrolling interests' share of $14.6 million and $6.8 million during the years ended December 31, 2014, and 2013, respectively, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C and QEP Midstream.

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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, 2015 and 2014, as compared to the years ended December 31, 2014 and 2013, by the average field-level price for the years ended December 31, 2014 and 2013.

(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, 2015 and 2014, as compared to the years ended December 31, 2014 and 2013, by the respective volumes for the years ended December 31, 2014 and 2013. Pricing changes are driven by changes in commodity field-level prices, excluding the impact from commodity derivatives.

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(1)	See discussion of revolving credit facility below. Availability under the QEP credit facility is reduced by outstanding letters of credit of $3.4 million and $3.7 million as of December 31, 2015 and 2014, respectively.

(2)	Defined as total debt divided by the sum of total debt plus common shareholders’ equity.

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•	$176.8 million 6.05% Senior Notes due September 2016;

•	$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)	Represents the mid-point of QEP's most recent guidance.

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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 credit facility.

(3)	Includes firm transportation rates that are subject to FERC approval and may change as a result of the outcome of pending approvals.

(4)	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 $45.9 million for the year ended December 31, 2013.

(2)	Presented net of income tax benefit of $0.3 million for the year ended December 31, 2015, net of income tax benefit of $8.5 million for the year ended December 31, 2014, and net of income tax expense of $8.3 million for the year ended December 31, 2013.

(3)	Presented net of income tax expense of $0.2 million, $0.3 million, and $0.9 million during the years ended December 31, 2015, 2014, and 2013, respectively.

(4)	Presented net of income tax expense of $4.9 million, $6.0 million, and $2.1 million during the years ended December 31, 2015, 2014, and 2013, respectively.

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

(6)	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 and $33.5 million for the years ended December 31, 2014 and 2013, respectively.

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(1)	Excludes $28.5 million of ARO as of January 1, 2014, classified as "Noncurrent liabilities of discontinued operations" on the Consolidated Balance Sheet.

(2)	Additions for the year ended December 31, 2014, include $9.7 million related to the 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)	Represents units that were not paid out due to performance under the Plan.

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(1)

In the fourth quarter of 2015, the Company determined that certain purchased oil transactions that had been included in "Revenues" and "Purchased gas and oil expense" on a gross basis should have been reported net, as the transactions were with the same counterparty and were entered into in contemplation of one another. The revisions had no effect on the Company’s operating income or net income. The following table details the impact to Eliminations of the revisions to the Consolidated Statement of Operations. See Note 1 – Summary of Significant Accounting Policies for additional information.

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(2)	In December 2014, QEP completed the Midstream Sale. QEP Field Services' financial results (excluding results of Haynesville Gathering) have been reflected as discontinued operations and all prior periods have been reclassified.

(3)	Includes net gains and losses from asset sales and losses due to asset impairments.

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(1)

Revisions of previous estimates in 2013 include positive impacts due to 80.0 Bcfe pricing revisions, negative performance revisions of 265.5 Bcfe, 42.0 Bcfe negative operating cost revisions and 101.0 Bcfe other negative revisions. Pricing revisions were primarily due to increased gas prices, which increased reserves by 68.4 Bcfe. Negative performance revisions were driven by a 129.5 Bcfe decrease in Pinedale reserves and 112.7 Bcfe decrease in Haynesville reserves related to reserve adjustments based on additional production history, well performance and current pricing causing a revised future development plan, which includes lower density drilling and a change in well spacing assumptions in some areas.

(2)

Extensions and discoveries in 2013 increased proved reserves by 783.8 Bcfe, primarily related to extensions and discoveries in the Williston Basin of 217.6 Bcfe, in Pinedale of 265.3 Bcfe, and 175.9 Bcfe in Haynesville. Extension and discoveries in Pinedale and Haynesville relate to certain less densely spaced wells with higher estimates of recoverable oil and gas, which were booked to replace wells removed from the Company's reserves through negative revisions caused by a change in well spacing assumptions in these areas. Of these extensions and discoveries, 687.6 Bcfe related to new PUD locations.

(3)

Revisions of previous estimates in 2014 include 248.5 Bcfe negative performance revisions partially offset by positive other revisions of 197.7 Bcfe, operating cost revisions of 39.2 Bcfe and pricing revisions of 22.9 Bcfe. Negative performance revisions were driven by a 194.0 Bcfe 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

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(4)	Extensions and discoveries in 2014 increased proved reserves by 294.1 Bcfe, primarily related to extensions and discoveries in Pinedale of 133.6 Bcfe and the Williston Basin of 123.3 Bcfe. All of these extensions and discoveries related to new well completions and the associated new PUD locations as part of the Company's development drilling plans and new compression well projections in Pinedale.

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

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

(7)	Revisions of previous estimates in 2015 include: 756.9 Bcfe of negative revisions due to lower pricing and 403.2 Bcfe of negative revisions unrelated to pricing, partially offset by 82.2 Bcfe of positive performance revisions. Negative pricing revisions were driven by lower gas, oil, and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and Uinta Basin.

(8)

Extensions and discoveries in 2015 increased proved reserves by 1,111.9 Bcfe, primarily related to extensions and discoveries in Williston Basin of 409.3 Bcfe, Uinta Basin of 318.9 Bcfe, and Permian Basin of 297.8 Bcfe. All of these extensions and discoveries related to new well completions and the associated new PUD locations as part of the Company's development drilling plans and new compression well projections in Pinedale.

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

(10)	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.

•	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.	I have reviewed this report of QEP Resources, Inc. on Form 10-K for the period ended December 31, 2015;

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, 2015;

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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