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•	impact of the sale of QEP Field Services Company's midstream business;

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

•	compliance with governmental regulations;

•	risks associated with hydraulic fracturing;

•	maintaining leasehold inventory by drilling;

•	adequacy of insurance;

•	timing and impact of proposed environmental legislation and studies;

•	strong liquidity position providing financial flexibility;

•	adequacy of the Company's production and reserves to meet term sales commitments;

•	ability to purchase gas to satisfy delivery commitments;

•	ability to pursue acquisition opportunities;

•	fair value and critical accounting estimates;

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

•	QEP’s growth strategies;

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

•	impact of global geopolitical and macroeconomic events;

•	plans to enter into derivative contracts and managing counterparty risk;

•	plans to drill or participate in wells;

•	results from planned drilling operations and production operations;

•	pro forma results for acquired properties;

•	the Company's liquidity and sufficiency of cash flow from operations, cash-on-hand and availability under its credit facility to fund the Company's planned capital expenditures and operating expenses;

•	plans to divest of non-core assets;

•	expected gain or loss on sale of assets;

•	factors impacting oil, gas and NGL prices;

•	seasonality of QEP's operating results;

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•	assumptions regarding equity compensation;

•	ability to realize income tax benefits;

•	recognition of compensation costs related to equity compensation grants;

•	obligations under drilling contracts;

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

•	the outcome of contingencies such as legal proceedings;

•	estimated accrual for loss contingencies and other items and likelihood that indemnification obligations will be satisfied;

•	financial impact of operational hazards;

•	future expenses and operating costs;

•	the amount, type and timing of derivative contracts and unrealized derivative gains and losses;

•	impact of nonperformance by trade creditors or joint venture partners;

•	adequacy of credit review procedures, loss reserves, customer deposits and collection procedures to protect against credit related issues;

•	the Company's credit rating;

•	loss of any large customer and the ability of the Company to replace customers;

•	expected contributions to the Company’s pension plans and returns from plan assets;

•	expected savings from service providers;

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

•	delays caused by transportation and refining capacity issues;

•	payment of dividends;

•	considerations regarding the standardized measure of future net cash flows relating to proved reserves;

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

•	factors impacting the timing and amount of share repurchases.

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

•	changes in gas, oil and NGL prices;

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

•	drilling results;

•	shortages of oilfield equipment, services and personnel;

•	lack of available pipeline, processing and refining capacity;

•	QEP's ability to successfully integrate acquired assets or divest of non-core assets;

•	the outcome of contingencies such as legal proceedings;

•	permitting delays;

•	operating risks such as unexpected drilling conditions;

•	weather conditions;

•	the availability and cost of debt and equity financing;

•	changes in laws or regulations;

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

•	derivative activities;

•	volatility in the commodity-futures market;

•	substantial liabilities from legal proceedings and environmental claims;

•	failure of internal controls and procedures;

•	failure of QEP's information technology infrastructure or applications;

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

•	regulatory approvals and compliance with contractual obligations;

•	actions, or inaction, by federal, state, local or tribal governments;

•	lack of, or disruptions in, adequate and reliable transportation for QEP's production;

•	competitive conditions;

•	production levels;

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•	reserve levels; and

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

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•	Incurred a net loss from continuing operations of $409.5 million, or $2.28 per diluted share, a decrease of $461.6 million from the net income from continuing operations of $52.1 million, or $0.29 per diluted share, in 2013;

•	Generated Adjusted EBITDA from continuing operations (a non-GAAP financial measure defined and reconciled in Item 7 of Part II of this Annual Report on Form 10-K) of $1,438.3 million, up from $1,316.0 million in 2013;

•	Increased liquids (oil and NGL) production by 59% to 143.4 Bcfe;

•	Increased liquid (oil and NGL) proved reserves by 7% to 1.6 Tcfe;

•	Added 294.1 Bcfe of proved reserves from extensions and discoveries;

•	Completed the Midstream Sale for approximately $2.5 billion, including $230.0 million to refinance debt at QEP Midstream, resulting in a pre-tax gain on sale of approximately $1.8 billion;

•	Completed the acquisition of oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $941.8 million; and

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

•	operate in a safe and environmentally responsible manner;

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

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

•	maintain a sustainable, diverse inventory of low-cost, high-margin resource plays;

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

•	build contiguous acreage positions that drive operating efficiencies;

•	be the operator of our assets, whenever possible;

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

•	actively market our production to maximize value;

•	utilize derivative contracts to mitigate the impact of gas, oil or NGL price volatility and fluctuating interest rates, while locking in acceptable cash flows required to support future capital expenditures;

•	attract and retain the best people; and

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

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

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

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

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

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

•	the availability of refining capacity;

•	domestic and global economic conditions;

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

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

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

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

•	the impact of U.S. dollar exchange rates on oil, NGL and natural gas prices;

•	weather conditions, weather forecasts and natural disasters;

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

•	technological advances affecting energy consumption and energy supply;

•	conservation efforts;

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

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

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

•	exports from the United States of oil, NGL and natural gas; and

•	the quality of oil and gas produced.

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

•	fire, explosions and blowouts;

•	aging infrastructure and mechanical problems;

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

•	pipe, cement or casing failures;

•	title problems;

•	equipment malfunctions and/or mechanical failure;

•	security breaches, cyberattacks, piracy, or terroristic acts;

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

•	severe weather that could affect QEP's operations;

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

•	truck and rail loading and unloading; and

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

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•	landing our wellbore in the desired drilling zone;

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

•	running our casing the entire length of the wellbore; and

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

•	the ability to fracture stimulate the planned number of stages;

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

•	the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

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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;

•	setback requirements from houses, schools and businesses;

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

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

•	increased severance and/or other taxes;

•	cyberattacks;

•	legal challenges or lawsuits;

•	negative publicity about QEP;

•	increased costs of doing business;

•	reduction in demand for QEP's products;

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

•	regulation of rail transportation of crude oil; and

•	construction of new oil and gas transmission pipelines.

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

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

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(1)	The increase in extensions and discoveries in 2014 was the result of 123.5 Bcfe in Pinedale and 84.7 Bcfe in the Williston Basin. All of these extensions and discoveries related to new well completions and the associated new PUD locations as part of the Company's development drilling plans and new compression projections in Pinedale.

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

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

(4)

All of QEP Energy's PUD reserves at December 31, 2014, are scheduled to be developed within five years from the date such locations were initially disclosed as PUD reserves; however, long-term development of gas reserves in Pinedale is governed by the BLM's September 2008 ROD on the FSEIS. Under the ROD, QEP Energy is allowed to drill and complete wells year-round in designated concentrated development areas. The ROD contains additional requirements and restrictions on the sequence of development, which requires the Company to develop its leasehold from the south to the north. These restrictions result in protracted, phased development that is beyond the control of the Company. The Company has an ongoing development plan and the financial capability to continue development in the manner estimated. Additionally, QEP Energy plans to develop its PUD reserves prior to lease expiration or extend the term of the lease.

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

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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)	QEP suspends Pinedale completion operations during the coldest months of the winter, generally from December to mid-March.

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•	A $100 investment was made in QEP's common stock, the S&P 500 Index and the Company's peer group as of July 1, 2010, which is the date when QEP's common stock began trading on the NYSE;

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•	Investment in the Company's peer group 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)	60,612 of the shares purchased during the three-month period ended December 31, 2014, were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants.

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(1)	During the years ended December 31, 2014, 2013 and 2012, the results are impacted by the Williston Basin Acquisition that occurred on September 27, 2012. See Note 2 - Acquisitions and Divestitures, in Item 8 of Part II this Annual Report on Form 10-K for detailed information on the Williston Basin Acquisition.

(2)

During the year ended December 31, 2014, the results are impacted by the Permian Basin Acquisition that occurred on February 25, 2014, and the property sales in the Midcontinent that occurred during 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 Permian Basin Acquisition and property divestitures.

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(3)

Revenue for the years ended December 31, 2011, and 2010, reflect the impact of QEP's settled derivative contracts, which during the years ended December 31, 2014, 2013 and 2012, are 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, 2014, 2013 and 2012.

(4)

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. Additionally, in June 2010, QEP completed a Spin-off from Questar. As a result of the Spin-off, Wexpro, a fully owned subsidiary of QEP, was distributed to Questar. Wexpro's financial results have been reflected as discontinued operations in 2010.

(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 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)	Separation costs represent costs incurred by QEP related to QEP's Spin-off from Questar in June 2010. Separation costs incurred by QEP related to the Midstream Sale in 2014 are included in "Discontinued operations, net of tax".

(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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(1)	Includes intercompany eliminations.

(2)	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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(3)	Excludes noncontrolling interests' share of $14.6 million, $6.8 million, and $2.8 million during the years ended December 31, 2014, 2013 and 2012, respectively, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C and QEP Midstream.

(4)	Includes certain significant litigation contingency items for the year ended December 31, 2012.

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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, 2014 and 2013, as compared to the years ended December 31, 2013 and 2012, by the average field-level price for the years ended December 31, 2013 and 2012.

(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, 2014 and 2013, as compared to the years ended December 31, 2013 and 2012, by the respective volumes for the years ended December 31, 2013 and 2012. 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 $3.7 million and $3.8 million as of December 31, 2014 and 2013, 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 end of the 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 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 and $101.3 million during the years ended December 31, 2013 and 2012, respectively.

(2)	Presented net of income tax benefit of $8.5 million for the year ended December 31, 2014, net of income tax expense of $8.3 million during the year ended December 31, 2013 and net of income tax benefit of $6.3 million during the year ended December 31, 2012.

(3)	Presented net of income tax expense of $0.3 million, $0.9 million and $0.9 million during the years ended December 31, 2014, 2013, and 2012, respectively.

(4)	Presented net of income tax expense of $6.0 million, $2.1 million and $2.2 million during the years ended December 31, 2014, 2013 and 2012, respectively.

(5)	Presented net of income tax expense of $3.5 million for the year ended December 31, 2014 and $0.8 million during the year ended December 31, 2012.

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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, $33.5 million and $38.9 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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(1)	Excludes $28.5 million and $37.5 million of ARO as of January 1, 2014 and 2013, respectively, classified as "Noncurrent liabilities of discontinued operations" on the Consolidated Balance Sheets.

(2)	Additions 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. Refer to Note 7 - Derivative Contracts, for additional information regarding the Company's derivative contracts.

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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. Refer to Note 7 - Derivative Contracts, for additional information regarding the Company's derivative contracts.

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(1)	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.

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

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(1)

Revisions of previous estimates in 2012 include negative impacts due to 152.4 Bcfe pricing revisions, 35.6 Bcfe performance revisions, 27.6 Bcfe operating cost revisions and 29.1 Bcfe other revisions. The 152.4 Bcfe pricing revisions were due to lower gas prices which reduced gas reserve volumes by 147.7 Bcf. Negative performance revisions were driven by a 56.0 Bcfe decrease in Pinedale reserves. Pinedale reserve adjustments are based on additional production history, well performance and current pricing causing a revised future development plan which includes lower density drilling in some flank areas, resulting in 25 proved undeveloped (PUD) locations being eliminated. Reserve decreases are partially offset by a 35.9 Bcfe positive impact from revisions in the Uinta Basin, due to the installation of the Iron Horse Cryogenic plant to increase liquid recoveries and improved well performance in the Red Wash Mesaverde field.

(2)

Extensions and discoveries in 2012 increased proved reserves by 572.5 Bcfe, primarily related to extensions and discoveries in the Uinta Basin of 258.3 Bcfe, in Pinedale of 151.6 Bcfe, and 162.6 Bcfe in the Williston Basin, Midcontinent and Other Northern areas of operation combined. 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.

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(3)	Purchase of reserves in place in 2012 primarily relate to the Company's $1.4 billion Williston Basin Acquisition as discussed in Note 2 - Acquisitions and Divestitures.

(4)

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 in some areas and a change in well spacing assumptions in these areas.

(5)

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.

(6)

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 lease operating expense deducts. Pricing revisions were primarily due to increased gas prices, which increased reserves by 21.9 Bcfe.

(7)	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.

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

(9)	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.

•	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.

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

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

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

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*	Filed with the Company's Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 24, 2015.

**	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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