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

•	our strategic objectives;

•	plans to review strategic alternatives and having discussions with various parties regarding a potential transaction;

•	plans to reduce general and administrative expenses significantly;

•	timing of the implementation of organizational changes;

•	evaluation of sale of Permian midstream assets and non-core assets;

•	restructuring costs associated with contractual termination benefits;

•	resolution of asserted title defects with respect to the Haynesville divestiture;

•	the termination of the planned Williston Basin divestiture and not realizing the expected benefits, and the impact on our strategic initiatives;

•	the effect of the strategic initiatives on employees and third parties;

•	the impact of the various divestitures associated with the strategic initiatives, including production and profitability projections;

•	plans to grow oil, condensate and gas production;

•	drilling and completion plans and strategies;

•	adding additional acreage in our operating areas;

•	estimated reserves and development of such reserves;

•	adequacy of procedures implemented to protect against credit-related losses;

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

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

•	reclassification of PUD reserves;

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

•	future development costs and funding sources for same;

•	factors affecting our decision to modify our development plans;

•	our ability to meet delivery and sales commitments;

•	the effect of lost customers on the financial position or results of operations;

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•	FERC regulation of oil and gas pipelines;

•	impact of tax legislation on our tax position and after-tax earnings or financial statements;

•	adequacy of insurance;

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

•	the effects of oil, gas and NGL prices on our business, including the execution of our strategic initiatives;

•	impact of shutting in wells;

•	factors impacting our ability to transport oil and condensate and gas;

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

•	credit agreement limitations on divestitures;

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

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

•	incurring penalties related to air emission noncompliance and capital expenditures to maintain or obtain operating permits and approvals;

•	the underfunded status of our pension plan;

•	the adjustments made to GAAP Measures to arrive at non-GAAP measures and the usefulness of non-GAAP financial measures;

•	our inventory of drilling locations and the ability of that inventory to provide a solid base for growth in production and reserves;

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

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

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

•	focus on operating costs and per well drilling costs;

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

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

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

•	potential for asset impairments and factors impacting impairment amounts;

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

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

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

•	outcome and impact of various claims;

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

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

•	predictability and success of our drilling operations;

•	plans and ability to pursue acquisition opportunities;

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

•	our plans regarding contributions to the nonqualified retirement plan (SERP), medical plan and 401(k) plan;

•	the estimated actuarial loss and services cost and discount rate assumptions related to our pension plan, the SERP and medical plan, as applicable;

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

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

•	off-balance sheet arrangements;

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

•	leasehold development and financial capability to continue planned development;

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

•	changes in recorded goodwill and bargain purchase gains;

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

•	redemption of senior notes

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

•	factors impacting bad debt expense;

•	unrecognized tax benefits and the realization of those benefits;

•	pro forma results for acquired properties;

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

•	assumptions regarding share-based compensation;

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

•	use of net operating losses;

•	alternative minimum tax credits amount and timing; and

•	expected costs associated with contractual termination benefits, including severance and accelerated vesting of share-based compensation, as part of the strategic initiatives and associated divestitures.

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

•	any potential impact from the announcement that the Board of Directors of the Company is conducting a review of strategic alternatives;

•	changes in oil, gas and NGL prices;

•	global geopolitical and macroeconomic factors;

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

•	the risks and liabilities associated with acquired assets;

•	asset impairments;

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

•	drilling and completion strategies, methods and results;

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

•	changes in estimated reserve quantities;

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

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

•	changes in development plans;

•	lack of available pipeline, processing and refining capacity;

•	processing volumes and pipeline throughput;

•	risks associated with hydraulic fracturing;

•	the outcome of contingencies such as legal proceedings;

•	delays in obtaining permits and governmental approvals;

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

•	weather conditions;

•

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

•	derivative activities;

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

•	volatility in the commodity-futures market;

•	failure of internal controls and procedures;

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

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

•	production, severance and property taxation rates;

•	discount rates;

•	regulatory approvals and compliance with contractual obligations;

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

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

•	competitive conditions;

•	production and sales volumes;

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

•	estimates of oil and gas reserve quantities;

•	reservoir performance;

•	operating costs;

•	inflation;

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•	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;

•	changes in guidance issued related to tax reform legislation;

•	actions of activist shareholders; and

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

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•	Entered into a purchase and sale agreement to sell its assets in Haynesville/Cotton Valley in 2019 for an aggregate purchase price of approximately $735.0 million, subject to purchase price adjustments;

•	Entered into a purchase and sale agreement to sell its assets in the Williston Basin in 2019 for a purchase price of $1,725.0 million, subject to purchase price adjustments;

•	Received $243.6 million proceeds from disposition of assets in 2018, including the Uinta Basin and other non-core assets, which were used to pay down debt;

•	Recognized a net realized oil price of $53.02 per bbl, a $4.80 per bbl increase compared to 2017;

•	Delivered oil equivalent production of 51.9 MMboe;

•	Delivered record oil and condensate production of 23.9 MMbbls, including a record 12.1 MMbbls in the Permian Basin;

•	Reported year-end total proved reserves of 658.2 MMboe, including record proved crude oil and condensate reserves of 339.1 MMbbls, a 6% increase compared to 2017;

•	Incurred capital expenditures (excluding property acquisitions) of $1,176.6 million, a 4% decrease over 2017;

•	Repurchased and retired 6.2 million shares of the Company's outstanding common stock for $58.4 million;

•	Generated a net loss of $1,011.6 million, or $4.25 per diluted share, primarily due to impairment expense of $1,560.9 million related to our Williston Basin and Uinta Basin assets; and

•	Reported $974.8 million of Adjusted EBITDA (a non-GAAP measure defined and reconciled in Item 7 of Part II of this Annual Report on Form 10-K), a 32% increase over 2017.

•	operate in a safe and environmentally responsible manner;

•	simplify our asset portfolio and focus on our oil basin assets;

•	maintain an inventory of high return development projects in our operating areas;

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

•	increase oil and condensate production as a percentage of total production;

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

•	build contiguous acreage positions that drive operating efficiencies;

•	be the operator of our assets, whenever possible;

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

•	actively market our production to maximize value;

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

•	attract and retain the best people; and

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

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

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

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

(2)	The reserve life index for 2018 excludes 2.2 MMboe of production volumes from the Uinta Basin due to the Uinta Basin Divestiture in September 2018. Including production volumes from the divested Uinta Basin assets, the reserve life index is 12.7 years for the year ended December 31, 2018.

(3)	The reserve life index for 2017 excludes 9.9 MMboe of production volumes from Pinedale due to the Pinedale Divestiture in September 2017. Including production volumes from the divested Pinedale assets, the reserve life index is 12.9 years for the year ended December 31, 2017.

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(1)	Uinta Basin PUD reserve conversions in 2018 include actual activity through the closing date of the Uinta Basin Divestiture.

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

(2)

Adjusted transportation and processing costs includes transportation and processing costs that are reflected as part of "Oil and condensate, gas and NGL sales" on the Consolidated Statements of Operations. Management adds these costs together with transportation and processing costs reflected on the Consolidated Statements of Operations to reflect the total operating costs associated with its production. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of the total production costs required to operate the wells for the period. This non-GAAP measure should be considered by the reader in addition to but not instead of, the financial statements prepared in accordance with GAAP. Refer to Note 2 – Revenue in Item 8 of Part II of this Annual Report on Form 10-K for more information.

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(1)	As a result of the Uinta Basin Divestiture, QEP no longer owns operated or non-operated productive wells in the Uinta Basin as of December 31, 2018. Refer to Note 3 – Acquisitions and Divestitures in Item 8 of Part II of this Annual Report on Form 10-K for more information.

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

(2)	Undeveloped acreage is leased acreage and mineral interests 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)	The number of gross operated drilling wells in the Permian Basin includes 10 wells for which surface casing has been set but as of December 31, 2018, no drilling rig was active.

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•	responding to actions by activist shareholders could be costly and time-consuming, disrupting our operations and diverting the attention of our management and employees;

•	such activities could interfere with our ability to execute our strategic plan or realize short- or long-term value from our assets;

•	such activities could interfere with our ability to pursue strategic alternatives to Elliott's proposal; and

•	the perceived uncertainties as to our future direction could also result in the loss of potential business opportunities, make it more difficult or costly to attract and retain qualified personnel and affect the market price and volatility of our securities.

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

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

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

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

•	the availability of refining and storage capacity;

•	domestic and global economic and political conditions;

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

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

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

•	the activities of the Organization of Petroleum Exporting Countries (OPEC) and other oil producing countries such as Russia, including the ability of members of OPEC and Russia 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 events in the Middle East, Africa, South America and Russia;

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

•	weather conditions and natural disasters;

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

•	technological advances affecting energy consumption and energy supply;

•	conservation efforts;

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

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

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

•	the quality of oil and gas produced.

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

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

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

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

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

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

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

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

•	cause additional counterparty credit risk;

•	decrease the value of QEP's common stock; and

•	increase shareholder activism.

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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;

•	equipment malfunctions, mechanical failures or accidents;

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

•	adverse weather conditions;

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

•	truck and rail loading and unloading problems;

•	delays imposed by or resulting from compliance with regulatory requirements;

•	delays in or limits on the issuance of drilling permits on our federal leases, including as a result of government shutdowns;

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

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

•	pipeline takeaway and refining and processing capacity issues; and

•	title problems.

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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 gathering, processing or pipeline facilities;

•	more stringent setback requirements from houses, schools, businesses and other improvements and landscape features;

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

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

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

•	increased severance and/or other taxes;

•	cyberattacks;

•	legal challenges or lawsuits;

•	negative publicity about QEP;

•	disinvestment and other targeted activist shareholder campaigns;

•	increased costs of doing business;

•	reduction in demand for QEP's production;

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

•	increased regulation of rail transportation of crude oil;

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

•	postponement of state oil and gas lease sales; and

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

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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 investing in oil and gas assets.

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

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

•	marketing its oil, gas and NGL production;

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

•	attracting and retaining employees with certain critical skills.

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

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

•	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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•	authorization for the issuance of "blank check" preferred stock that our board of directors could issue to increase the number of outstanding shares to discourage a takeover attempt;

•	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, 2013, and its relative performance is tracked through December 31, 2018;

•	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. QEP suspended the payment of dividends in February 2016.

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(1)	During the three months ended December 31, 2018, QEP purchased 96,463 shares from employees in connection with the settlement of income tax and related benefit withholding obligations arising from the vesting of restricted share grants.

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(1)	The results are impacted by various acquisitions and divestitures. Refer to Note 3 – Acquisitions and Divestitures in Item 8 of Part II of this Annual Report on Form 10-K for more information on these transactions.

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(2)

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.

(3)	In the first quarter of 2018, QEP adopted ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), using the modified retrospective approach. During the year ended December 31, 2018, the revenues are impacted by the adoption of this ASU. Refer to Note 2 – Revenue in Item 8 of Part II of this Annual Report on Form 10-K for more information.

(4)

In the first quarter of 2017, QEP early adopted ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, which is effective retrospectively. As a result, the Company has recast operating income and Adjusted EBITDA for the years ended December 31, 2016, 2015 and 2014. The Company recognizes service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of Operations and all other expenses related to the Pension Plan, SERP and Medical Plan are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations. Refer to Note 12 – Employee Benefits in Item 8 of Part II of this Annual Report on Form 10-K for more information.

(5)	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 year ended December 31, 2014, have been reclassified.

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

(7)

In the first quarter of 2018, QEP adopted ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted cash, which is effective retrospectively. As a result, the Company has recast net cash provided by (used in) operating activities for the years ended December 31, 2017, 2016, 2015 and 2014. Refer to Note 1 – Summary of Significant Accounting Policies in Item 8 of Part II of this Annual Report on Form 10-K for more information.

(8)

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

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(1)

In the first quarter of 2017, QEP early adopted ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, which is effective retrospectively. As a result, the Company recast "Interest and other (income) expense" and "Other" for the years ended December 31, 2016, 2015 and 2014. The Company recognizes service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of Operations and all other expenses related to the Pension Plan, SERP and Medical Plan benefits are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations. Refer to Note 12 – Employee Benefits in Item 8 of Part II of this Annual Report on Form 10-K for more information.

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

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•	Entered into a purchase and sale agreement to sell its assets in Haynesville/Cotton Valley in 2019 for an aggregate purchase price of approximately $735.0 million, subject to purchase price adjustments;

•	Entered into a purchase and sale agreement to sell its assets in the Williston Basin in 2019 for a purchase price of $1,725.0 million, subject to purchase price adjustments;

•	Received $243.6 million proceeds from disposition of assets in 2018, including the Uinta Basin and other non-core assets, which were used to pay down debt;

•	Recognized a net realized oil price of $53.02 per bbl, a $4.80 per bbl increase compared to 2017;

•	Delivered oil equivalent production of 51.9 MMboe;

•	Delivered record oil and condensate production of 23.9 MMbbls, including a record 12.1 MMbbls in the Permian Basin;

•	Reported year-end total proved reserves of 658.2 MMboe, including record proved crude oil and condensate reserves of 339.1 MMbbls, a 6% increase compared to 2017;

•	Incurred capital expenditures (excluding property acquisitions) of $1,176.6 million, a 4% decrease over 2017;

•	Repurchased and retired 6.2 million shares of the Company's outstanding common stock for $58.4 million;

•	Generated a net loss of $1,011.6 million, or $4.25 per diluted share, primarily due to impairment expense of $1,560.9 million related to our Williston Basin and Uinta Basin assets; and

•	Reported $974.8 million of Adjusted EBITDA (a non-GAAP measure defined and reconciled in Item 7 of Part II of this Annual Report on Form 10-K), a 32% increase over 2017.

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(1)

In the first quarter of 2017, QEP early adopted ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, which is effective retrospectively. As a result, the Company recast "Interest and other (income) expense" and "Other" for the year ended December 31, 2016. The Company recognizes service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of Operations and all other expenses related to the Pension Plan, SERP and Medical Plan benefits are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations. Refer to Note 12 – Employee Benefits in Item 8 of Part II of this Annual Report on Form 10-K for more information.

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

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(1)	Prior period amounts have not been adjusted under the modified retrospective method for the new revenue recognition rule. Refer to Note 2 – Revenue in Item 8 of Part II of this Annual Report on Form 10-K for more information.

(2)	Transportation and processing costs in the table above are not representative of total transportation and processing costs incurred for the year ended December 31, 2018. Refer to the Operating Expenses section below for a reconciliation of total transportation and processing costs.

(3)

Above is a reconciliation of Oil and condensate, gas and NGL sales (a GAAP measure) as presented on the Consolidated Statements of Operations to Oil and condensate, gas and NGL sales, as adjusted (a non-GAAP measure). Oil and condensate, gas and NGL sales, as adjusted excludes transportation and processing costs that are included as part of "Oil and condensate, gas and NGL sales" on the Consolidated Statements of Operations. Management removes these costs from "Oil and condensate, gas and NGL sales" included on the Consolidated Statements of Operations to reflect total revenue associated with its production prior to deducting any expenses. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of the total revenue generated from its wells for the period. This non-GAAP measure should be considered by the reader in addition to but not instead of, the financial measure prepared in accordance with GAAP. Refer to Note 2 – Revenue in Item 8 of Part II of this Annual Report on Form 10-K for more information.

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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, 2018 and 2017, as compared to the years ended December 31, 2017 and 2016, by the average field-level price for the years ended December 31, 2017 and 2016, respectively.

(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, 2018 and 2017, as compared to the years ended December 31, 2017 and 2016, by the respective volumes for the years ended December 31, 2018 and 2017, respectively. Pricing changes are driven by changes in commodity field-level prices, excluding the impact from commodity derivatives.

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(1)

Below are reconciliations of transportation and processing costs (a GAAP measure) as presented on the Consolidated Statements of Operations and on a unit of production basis to adjusted transportation and processing costs. Adjusted transportation and processing costs includes transportation and processing costs that are reflected as part of "Oil and condensate, gas and NGL sales" on the Consolidated Statements of Operations. Management adds these costs together with transportation and processing costs reflected on the Consolidated Statements of Operations to reflect the total operating costs associated with its production. Management believes that this non-GAAP measure is useful supplemental information for investors as it is reflective of the total production costs required to operate the wells for the period. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP. Refer to Note 2 – Revenue in Item 8 of Part II of this Annual Report on Form 10-K for more information.

(1)	Prior period amounts have not been adjusted under the modified retrospective method for the new revenue recognition rule. Refer to Note 2 – Revenue in Item 8 of Part II of this Annual Report on Form 10-K for more information.

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

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

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

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

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

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

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

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

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(1)	Refer to New Accounting Pronouncements in Note 1 – Summary of Significant Accounting Policies.

(2)	Presented net of income tax benefit of $0.1 million for the year ended December 31, 2018 and net of income tax expense of $0.8 million for the year ended December 31, 2017.

(3)	Presented net of income tax benefit of $1.3 million for the year ended December 31, 2018, net of income tax expense of $1.8 million for the year ended December 31, 2017 and net of income tax benefit of $3.3 million for the year ended December 31, 2016.

(4)	Presented net of income tax expense of $0.1 million, $0.2 million and $0.5 million for the years ended December 31, 2018, 2017 and 2016, respectively.

(5)	Presented net of income tax expense of $0.2 million, $0.1 million and $0.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.

(6)	Presented net of income tax expense $0.1 million for the year ended December 31, 2017.

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(1)	Refer to New Accounting Pronouncements in Note 1 – Summary of Significant Accounting Policies.

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(1)	As of December 31, 2018 and 2017, the restricted cash balance related to cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin, and the restricted cash balance is recorded within "Other noncurrent assets" on the Consolidated Balance Sheets.

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(1)	This column excludes the impact of adopting ASC Topic 606 and is consistent with the presentation prior to January 1, 2018.

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(1)	For the year ended December 31, 2018, immaterial amounts of revenue associated with adjustments in Pinedale have been included in Other Northern.

(2)	Prior period amounts have not been adjusted under the modified retrospective method.

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(1)	For the year ended December 31, 2017, the asset and liabilities held for sale also includes the Uinta Basin Divestiture.

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(1)	Additions for the year ended December 31, 2017, include $14.2 million related to the 2017 Permian Basin Acquisition. Refer to Note 3 – Acquisitions and Divestitures for more information.

(2)	Liabilities related to assets sold for the year ended December 31, 2018, includes $51.0 million related to the Uinta Basin Divestiture. Liabilities related to assets sold for the year ended December 31, 2017 includes $34.9 million related to the Pinedale Divestiture. Refer to Note 3 – Acquisitions and Divestitures for more information.

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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 more information regarding the Company's derivative contracts.

(2)	Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of December 31, 2018 and "Other long-term liabilities held for sale" of $3.0 million as of December 31, 2017 on the Consolidated Balance Sheets related to the Haynesville Divestiture.

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(1)	Includes fair value of derivative contracts classified as "Noncurrent assets held for sale" of $0.3 million as of December 31, 2018 and "Other long-term liabilities held for sale" of $3.0 million as of December 31, 2017 on the Consolidated Balance Sheets related to the Haynesville Divestiture.

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(1)

During the year ended December 31, 2018, the unrealized gains (losses) on commodity derivative contracts related to the Uinta Basin Divestiture are comprised of derivatives entered into in conjunction with the execution of the Uinta Basin purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2018. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Uinta Basin Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations.

(2)

During the year ended December 31, 2017, the unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 3 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales, inclusive of restructuring costs" on the Consolidated Statements of Operations.

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(1)	Accelerated share based compensation represents the additional expense or loss recognized in the Consolidated Statement of Operations for the year ended December 31, 2018. Total accelerated share based compensation was $11.2 million and was determined based on the contractual vesting date, with $11.0 million recognized in 2018 as shown above, and the remaining amount recognized in prior periods.

(1)	Due to the nature of the strategic initiatives and uncertain factors such as the timing and terms of the potential divestitures, the Company is not able to reasonably estimate the total cost to be incurred as a part of these restructurings.

(2)	In January 2019, QEP had $15.5 million of accelerated share-based compensation due to the departure of two officers. The accelerated share-based compensation of $15.5 million was determined based on the contractual vesting date with $6.0 million expected to be recognized in the first quarter of 2019 and the remaining amount previously recognized in 2018 and prior periods.

(3)	QEP expects to incur an additional $3.9 million in 2019 related to the 2018 retention program and $17.5 million related to the 2019 retention program, which includes $16.0 million of cash and $1.5 million of share-based compensation.

(4)	Refer to the Note 16 – Subsequent Events for more information regarding expected restructuring costs.

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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 years ended December 31, 2018 and 2017, the rate of increase in compensation is only used for the SERP.

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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, 2018, the rate of increase in compensation is only used for the SERP. For the year ended December 31, 2017, the rate of increase in compensation is only used for the SERP and Medical Plan.

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(1)	State income taxes changed significantly from prior years mainly due to the change in valuation allowance recorded during 2017 of $36.2 million.

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

(3)	In 2018, QEP agreed to an IRS proposed change to the initial treatment of the 2016 carryback of net operating losses. This change resulted in a reduction of available net operating loss carryforwards valued at $75.7 million and an increase in alternative minimum tax (AMT) credit carryforwards of $126.0 million. The net change in value of $50.3 million was recorded in deferred income taxes.

(1)	Net operating losses created in tax years beginning after December 31, 2017 can be carried forward indefinitely under the Tax Legislation (limited to 80% of taxable income computed without the net operating loss deduction).

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

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(1)

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.

(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 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in Note 3 – Acquisitions and Divestitures.

(4)	Sale of reserves in place in 2016 relates to the divestiture of QEP's interest in certain non-core properties as discussed in Note 3 – Acquisitions and Divestitures.

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(5)

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

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

(7)	Purchase of reserves in place in 2017 was primarily related to QEP's 2017 Permian Basin Acquisition and various other acquired oil and gas properties as discussed in Note 3 – Acquisitions and Divestitures.

(8)	Sale of reserves in place in 2018 was primarily related to QEP's Pinedale Divestiture as discussed in Note 3 – Acquisitions and Divestitures.

(9)

Revisions of previous estimates in 2018 totaling 61.0 MMboe of positive revisions include 23.4 MMboe of other revisions, primarily related to changing our development plans in the Haynesville/Cotton Valley; 17.3 MMboe of positive revisions related to pricing, primarily driven by higher oil prices; 11.7 MMboe of positive revisions related to lower operating costs; and 8.7 MMboe of positive performance revisions.

(10)	Extensions and discoveries in 2018 primarily related to new well completions and associated new PUD locations in the Permian Basin.

(11)	Purchase of reserves in place in 2018 primarily relates to the additional acquisitions in the Permian Basin as discussed in Note 3 – Acquisitions and Divestitures.

(12)	Sale of reserves in place in 2018 was primarily related to QEP's Uinta Basin Divestiture as discussed in Note 3 – Acquisitions and Divestitures.

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

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•	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 and do not reflect cost savings of Company owned midstream operations on future operating expenses.

•	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.

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

(2)	The standardized measure of discounted future net cash flows for the year ended December 31, 2018 and 2017, were estimated assuming a 21% federal tax rate from the Tax Legislation enacted in December 2017.

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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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