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•	continue generating high margin returns from top tier projects that drive cash flow growth;

•	core up our portfolio (PRB Divestiture) to focus on assets that generate the highest returns; and

•	improve our credit metrics and maintain strong financial flexibility.

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(1)	Amounts may not calculate due to rounding.

(2)

As of December 31, 2017, a majority of our Powder River Basin assets were held for sale, and subsequent to December 31, 2017, we entered into the PRB Divestiture agreement. These assets represented approximately 4.2 MMBOE of our estimated proved reserves as of December 31, 2017, and approximately 1.0 MMBOE of 2017 production on an equivalent basis. There can be no assurance that the PRB Divestiture will close on time or at all.

(3)	Amounts do not sum to total costs incurred due primarily to corporate overhead charges incurred on exploration activity that are excluded from this regional table. Please refer to the caption Costs Incurred in Oil and Gas Producing Activities in the Supplemental Oil and Gas Information section in Part II, Item 8 of this report.

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(1)	Amounts may not calculate due to rounding.

(2)	For the years ended December 31, 2017, 2016, and 2015, proved gas reserves contained 48.1 Bcf, 43.7 Bcf, and 48.1 Bcf of gas, respectively, that we expect to produce and use as field fuel (primarily for compressors).

(3)	As of December 31, 2017, a majority of our Powder River Basin assets were held for sale, and subsequent to year end 2017, we entered into the PRB Divestiture agreement. These assets represented approximately 4.2 MMBOE of our total estimated proved reserves as of December 31, 2017. There can be no assurance that the PRB Divestiture will close on time or at all.

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(1)	We added 132.4 MMBOE of infill proved undeveloped reserves, primarily from our Midland Basin and Eagle Ford shale programs, and an additional 0.4 MMBOE of proved undeveloped reserves through various extensions and discoveries. We added 76.7 MMBOE and 54.8 MMBOE of proved undeveloped reserves in our Midland Basin and Eagle Ford shale programs, respectively, in 2017.

(2)	Sale of proved undeveloped reserves resulting from the divestiture of our outside-operated Eagle Ford shale assets during the first quarter of 2017.

(3)

Proved undeveloped reserves were reduced by 13.9 MMBOE due to changes in our development plan, which caused these locations to be reclassified primarily to the probable reserves category due to the five-year rule. These locations, which were predominately located in our Eagle Ford shale program, were replaced by higher quality proved undeveloped reserves, which are classified as extensions or infills in the table above, and resulted from our testing and delineation programs.

(4)

Conversions of proved undeveloped reserves to proved developed reserves were primarily in our Midland Basin and Eagle Ford shale programs. Our 2017 conversion track record was approximately 11 percent due to fewer conversions of proved undeveloped reserves in our Eagle Ford shale and Rocky Mountain programs as we focused on developing our Midland Basin assets, which had minimal proved undeveloped reserves booked at year end 2016. We expect our conversion track record to increase in 2018 as a result of increased capital expenditures related to converting proved undeveloped reserves added during 2017 in our Midland Basin program. During 2017, we incurred approximately $187 million on projects associated with reserves booked as proved undeveloped at the end of 2016, of which approximately $165 million was spent on proved undeveloped reserves converted to proved developed reserves by December 31, 2017. At December 31, 2017, drilled but not completed wells represented 31.0 MMBOE of total proved undeveloped reserves. We expect to incur approximately $193 million of capital expenditures in completing these drilled but not completed wells, and we expect all proved undeveloped reserves to be converted to proved developed reserves within five years from their initial booking as proved undeveloped reserves.

(5)	As of December 31, 2017, none of our proved undeveloped reserves were on acreage expected to expire or on acreage that was not expected to be held through renewal before their targeted completion date.

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(1)	Amounts may not calculate due to rounding.

(2)

As of December 31, 2017, total estimated proved reserves attributed to our Midland Basin properties exceeded 15 percent of our total estimated proved reserves expressed on an equivalent basis. For each of the annual periods presented, total estimated proved reserves attributed to our Eagle Ford shale properties also exceeded 15 percent of our total estimated proved reserves expressed on an equivalent basis. During each of the annual periods presented, no other field exceeded 15 percent of our total estimated proved reserves on an equivalent basis.

(3)	During the first quarter of 2017, we completed a divestiture of our outside-operated Eagle Ford shale assets. These assets represented approximately 1.5 MMBOE, 9.7 MMBOE, and 12.0 MMBOE of net production on an equivalent basis for the years ended December 31, 2017, 2016, and 2015, respectively.

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(1)	Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but has been included only as developed acreage in the presentation above.

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

(3)	As of February 14, 2018, approximately 17,900, 10,200, and 5,300 net acres of undeveloped acreage are scheduled to expire by December 31, 2018, 2019, and 2020, respectively, if production is not established or we take no other action to extend the terms of the applicable lease or leases.

(4)	Approximately 112,000 net acres of our Powder River Basin acreage was held for sale as of December 31, 2017, and subsequent to December 31, 2017, we entered into the PRB Divestiture agreement. There can be no assurance that the PRB Divestiture will close on time or at all.

(5)	Includes other non-core acreage located in North Dakota, Montana, Wyoming, and Utah.

(6)	Includes other non-core acreage.

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(1)	This major customer is a purchaser of a portion of our production from our Permian region.

(2)

This major customer was the operator in our outside-operated Eagle Ford shale program, which we divested during the first quarter of 2017. Prior to the divestiture, we were party to various marketing agreements whereby we were subject to certain gathering, transportation, and processing throughput commitments. Because we shared with the operator the risk of non-performance by its counterparty purchasers, we included the operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts were also direct purchasers of our production from other areas.

(3)	In the aggregate, these groups of entities under common ownership represent more than 10 percent of total oil, gas, and NGL production revenue for at least one of the periods shown; however, none of the individual entities comprising either group represented more than 10 percent of our total oil, gas, and NGL production revenue.

(1)	During the third quarter of 2015, we closed our office in Tulsa, Oklahoma. We have subleased this space through 2019, and our lease expires in 2022.

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•	require the acquisition of various permits before drilling commences;

•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling and production and saltwater disposal activities;

•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and

•	require remedial measures to mitigate pollution from former and ongoing operations, such as closing pits and plugging abandoned wells.

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•	the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;

•	our outlook on future oil, gas, and NGL prices, well costs, and service costs;

•	the drilling of wells and other exploration and development activities and plans, as well as possible or expected acquisitions or divestitures;

•	the possible divestiture or farm-down of, or joint venture relating to, certain properties;

•	proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;

•	future oil, gas, and NGL production estimates;

•	cash flows, anticipated liquidity, and the future repayment of debt;

•	business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and

•	other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in Part II, Item 7 of this report.

•	the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;

•	weakness in economic conditions and uncertainty in financial markets;

•	our ability to replace reserves in order to sustain production;

•	our ability to raise the substantial amount of capital required to develop and/or replace our reserves;

•	our ability to compete against competitors that have greater financial, technical, and human resources;

•	our ability to attract and retain key personnel;

•	the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves;

•	the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;

•	the possibility that exploration and development drilling may not result in commercially producible reserves;

•	our limited control over activities on outside-operated properties;

•	our reliance on the skill and expertise of third-party service providers on our operated properties;

•	the possibility that title to properties in which we claim an interest may be defective;

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•	our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;

•	the uncertainties associated with acquisitions, divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate (including any delay in our planned PRB Divestiture as a result of litigation);

•	the uncertainties associated with enhanced recovery methods;

•	our commodity derivative contracts may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales;

•	the inability of one or more of our service providers, customers, or contractual counterparties to meet their obligations;

•	our ability to deliver required quantities of oil, gas, NGL, or water to contractual counterparties;

•	price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;

•	the impact that depressed oil, gas, or NGL prices could have on our borrowing capacity under our Credit Agreement;

•	the possibility our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt;

•	the possibility that covenants in our Credit Agreement or the indentures governing the Senior Notes and Senior Convertible Notes may limit our discretion in the operation of our business, prohibit us from engaging in beneficial transactions or lead to the accelerated payment of our debt;

•	operating and environmental risks and hazards that could result in substantial losses;

•	the impact of seasonal weather conditions and lease stipulations on our ability to conduct drilling activities;

•	our ability to acquire adequate supplies of water and dispose of or recycle water we use at a reasonable cost in accordance with environmental and other applicable rules;

•	complex laws and regulations, including environmental regulations, that result in substantial costs and other risks;

•	the availability and capacity of gathering, transportation, processing, and/or refining facilities;

•	our ability to sell and/or receive market prices for our oil, gas, and NGLs;

•	new technologies may cause our current exploration and drilling methods to become obsolete;

•	the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and

•	litigation, environmental matters, the potential impact of legislation and government regulations, and the use of management estimates regarding such matters.

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•	global and domestic supplies of oil, gas, and NGLs, and the productive capacity of the industry as a whole;

•	the level of consumer demand for oil, gas, and NGLs;

•	overall global and domestic economic conditions;

•	weather conditions;

•	the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas;

•	liquefied natural gas deliveries to and from the United States;

•	the price and availability of alternative fuels;

•	technological advances and regulations affecting energy consumption and conservation;

•	the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to maintain effective oil price and production controls;

•	political instability or armed conflict in oil or gas producing regions;

•	strengthening and weakening of the United States dollar relative to other currencies; and

•	governmental regulations and taxes.

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•	the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;

•	the liquidity available under our Credit Agreement could be reduced if any lender is unable to fund its commitment;

•	our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for the exploration and/or development of reserves;

•	our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; and

•	variable interest rate spread levels, including for LIBOR and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our Credit Agreement.

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•	limit our ability to access debt markets, including for the purpose of refinancing our existing debt;

•	cause us to refinance or issue debt with less favorable terms and conditions, which debt may restrict, among other things, our ability to make any dividend distributions or repurchase shares;

•	negatively impact current and prospective customers’ willingness to transact business with us;

•	impose additional insurance, guarantee and collateral requirements;

•	limit our access to bank and third-party guarantees, surety bonds and letters of credit; and

•	cause our suppliers and financial institutions to lower or eliminate the level of credit provided through payment terms or intraday funding when dealing with us, thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay outstanding indebtedness.

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•	amount and timing of actual production;

•	supply and demand for oil, gas, and NGLs;

•	curtailments or increases in consumption by oil purchasers and gas pipelines;

•	changes in government regulations or taxes, including severance and excise taxes; and

•	escalations or reductions in service provider and equipment costs resulting from changes in supply and demand.

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•	unexpected adverse drilling or completion conditions;

•	title problems;

•	disputes with owners or holders of surface interests on or near areas where we operate;

•	pressure or geologic irregularities in formations;

•	engineering and construction delays;

•	equipment failures or accidents;

•	hurricanes, tornadoes, flooding, or other adverse weather conditions;

•	governmental permitting delays;

•	compliance with environmental and other governmental requirements; and

•	shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies.

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•	our production is less than expected;

•	one or more counterparties to our commodity derivative contracts default on their contractual obligations; or

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•	there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement.

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•	making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements;

•	requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to productive investments;

•	limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends;

•	placing us at a competitive disadvantage compared to our competitors with less debt; and

•	making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.

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•	incur additional debt;

•	make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire common stock;

•	sell assets, including common stock of our subsidiaries;

•	restrict dividends or other payments of our subsidiaries;

•	create liens that secure debt;

•	enter into transactions with affiliates; and

•	merge or consolidate with another company.

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•	requirements for methane emission reductions from existing oil and gas equipment;

•	increased scrutiny for sources emitting high levels of methane, including during permitting processes;

•	analysis, regulation and reduction of methane emissions as a requirement for project approval; and

•	actions taken by one agency for a specific industry establishing precedents for other agencies and industry sectors.

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•	changes in oil, gas, or NGL prices;

•	variations in drilling, recompletion, and operating activity;

•	changes in financial estimates by securities analysts;

•	changes in market valuations of comparable companies;

•	additions or departures of key personnel;

•	increased volatility due to the impacts of algorithmic trading practices;

•	future sales of our common stock; and

•	changes in the national and global economic outlook.

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ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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(1)	All shares purchased by us in 2017 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs delivered under the terms of grants under the Equity Incentive Compensation Plan (“Equity Plan”).

(2)

In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the filing of this report, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes and Senior Convertible Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flows, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time. Please refer to Dividends above for a description of our dividend limitations.

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(1)	Amounts may not calculate due to rounding.

(2)

Certain prior period amounts have been reclassified to conform to the current period presentation on the consolidated financial statements. Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies of Part II, Item 8 for additional discussion of the change in presentation on the accompanying statements of cash flows as a result of adopting new accounting standards.

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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

•

We recorded a net loss of $160.8 million, or $1.44 per diluted share, for the year ended December 31, 2017. This compares with a net loss of $757.7 million, or $9.90 per diluted share, for the year ended December 31, 2016. Please refer to Comparison of Financial Results and Trends Between 2017 and 2016 and Between 2016 and 2015 below for additional discussion regarding the components of net loss for each period presented.

•

At year end 2017, our estimated proved reserves totaled 468.1 MMBOE, of which 54 percent were liquids (oil and NGLs) and 46 percent were characterized as proved developed. During 2017, we added 175.0 MMBOE through our drilling program and acquired 1.3 MMBOE. We had positive revisions totaling 16.6 MMBOE, consisting of 23.1 MMBOE of price revisions due to increased commodity prices in 2017 and 7.4 MMBOE of positive performance revisions, offset by 13.9 MMBOE of proved undeveloped reserves removed due to the five year rule. Further, we divested of 76.0 MMBOE of proved reserves in 2017, which primarily related to our outside-operated Eagle Ford shale assets. Our proved reserve life index increased significantly to 10.5 years in 2017 compared to 7.2 years in 2016. Please refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion.

•	The standardized measure of discounted future net cash flows was $3.0 billion as of December 31, 2017, compared with $1.2 billion as of December 31, 2016, which was an increase of 162 percent year-over-year. Please refer to Supplemental Oil and Gas Information in Part II, Item 8 of this report for additional discussion.

•	We had net cash provided by operating activities of $515.4 million for the year ended December 31, 2017, compared with $552.8 million for the year ended December 31, 2016, which was a decrease of seven percent year-over-year. Please refer to Analysis of Cash Flow Changes Between 2017 and 2016 and Between 2016 and 2015 below for additional discussion.

•	Adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2017, was $664.7 million, compared with $790.8 million for the same period in 2016. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and a reconciliation of our net loss and net cash provided by operating activities to adjusted EBITDAX.

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(1)	Reflects net working interest changes resulting from the Eagle Ford North joint venture agreement discussed above, as well as three previously drilled wells that we no longer intend to complete.

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(1)	Amounts may not calculate due to rounding.

(1)	Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information in Part II, Item 8 of this report.

•	We acquired approximately 3,600 net acres of primarily unproved properties in Howard and Martin Counties, Texas, in multiple transactions for a total of $76.5 million of cash consideration. We also completed several non-monetary acreage trades in Howard and Martin Counties, Texas, that are excluded from the costs incurred table presented above.

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•	During 2017, we finalized the 2016 acquisitions of Midland Basin properties from Rock Oil Holdings, LLC and from QStar LLC and RRP-QStar, LLC by paying additional cash consideration of $7.7 million and $7.3 million, respectively.

•	On March 10, 2017, we divested our outside-operated Eagle Ford shale assets, including our ownership interest in related midstream assets, for net divestiture proceeds of $744.1 million and a final net gain of $396.8 million.

•	During 2017, we divested certain non-core properties in our Rocky Mountain and Permian regions for net divestiture proceeds of $36.2 million.

•	During the second quarter of 2017, we made the decision to retain our Divide County, North Dakota assets previously held for sale, as offers submitted in the sales process did not reach our expectations. During the year ended December 31, 2017, we recorded a $526.5 million write-down on these assets.

•

As of December 31, 2017, the majority of our Powder River Basin assets were classified as held for sale. Subsequent to year end, we executed a definitive sales agreement related to these assets for a gross purchase price of $500.0 million, subject to customary closing price adjustments. We expect the sale of these assets to close in the first quarter of 2018, but there can be no assurance it will close on time or at all.

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(1)	Gas derivative settlements for the year ended December 31, 2015, included $15.3 million of early settlements of futures contracts as a result of divesting assets in our Mid-Continent region. These early settlements increased the effect of derivative settlements by $0.09 per Mcf for the year ended December 31, 2015.

(2)	Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

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•	continue generating high margin returns from top tier projects that drive cash flow growth;

•	core up our portfolio (PRB Divestiture) to focus on assets that generate the highest returns; and

•	improve our credit metrics and maintain strong financial flexibility.

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(1)	Amounts and percentage changes may not calculate due to rounding.

(2)	Gas derivative settlements for the year ended December 31, 2015 included $15.3 million of early settlements of futures contracts as a result of divesting assets in our Mid-Continent region. These early settlements increased the effect of derivative settlements by $0.24 per BOE for the year ended December 31, 2015.

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(1)	We divested our Mid-Continent assets in the second quarter of 2015.

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(1)	Long-term debt consists of our Senior Notes and Senior Convertible Notes, and assumes no principal repayment until the due dates of the instruments. The actual payments may vary significantly. As of December 31, 2017, we had a zero balance on our revolving credit facility.

(2)	Interest payments on our Senior Notes and Senior Convertible Notes are estimated assuming no principal repayment until the due dates of the instruments. As our credit facility balance was zero at December 31, 2017, the above table reflects only the fee that would be paid on the unused credit facility’s aggregate lender commitment amount through the maturity date of the Credit Agreement.

(3)

Please refer to Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional discussion regarding our operating leases, contracts and gathering, processing, transportation throughput, and delivery commitments. The amount relating to our gathering, processing, transportation throughput, and delivery commitments reflects the aggregate undiscounted deficiency payments assuming we delivered no product.

(4)

Amounts shown represent estimated future undiscounted plugging and abandonment costs. The discounted obligations are recorded as liabilities on our accompanying consolidated balance sheets (“accompanying balance sheets”) as of December 31, 2017. The timing and amount of the ultimate settlement of these obligations is unknown and can be impacted by economic factors, a change in development plans, and federal and state regulations. Obligations related to inactive wells or wells that are not economic at current commodity price levels as of December 31, 2017, are shown as an obligation in 1-3 years due to the substantial uncertainty on the timing of plugging or re-entering these wells. Please refer to Note 9 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion.

(5)

Amounts shown represent only the liability portion of the marked-to-market value of our commodity derivatives based on future market prices as of December 31, 2017, and exclude estimated oil, gas, and NGL commodity derivative receipts. This amount varies from the liability amounts presented on the accompanying balance sheets, as those amounts are presented at fair value, which considers time value, volatility, and the risk of non-performance for us and for our counterparties. The ultimate settlement amounts under our derivative contracts are unknown, as they are subject to continuing market risk and commodity price volatility. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.

(6)	The majority of this amount is related to the unfunded portion of our estimated pension liability of $41.0 million, for which we have estimated the timing of future payments based on historical annual contribution amounts.

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(1)	The change solely reflects the impact of a 10 percent decrease in SEC pricing to the total reported estimated proved reserve volumes as of December 31, 2017, and does not include additional impacts to our estimated proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs.

(2)

The impact of replacing SEC pricing with average NYMEX strip pricing as of December 31, 2017, did not result in a meaningful change to our total reported proved reserve volumes as SEC pricing of $51.34 per Bbl for oil, $3.00 per MMBtu for gas, and $27.69 per Bbl for NGLs as of December 31, 2017, was not materially different than five year average NYMEX strip pricing of $54.71 per Bbl for oil, $2.84 per MMBtu for gas, and $29.22 per Bbl for NGLs as of December 31, 2017.

(3)	The change solely reflects a 10 percent decrease in proved undeveloped reserves as of December 31, 2017, and does not include any additional impacts to our estimated proved reserves.

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(1)	Interest income is included in “Other, net” on the accompanying statements of operations in Part II, Item 8 of this report.

(2)	Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

(3)	Derivative settlement gain for the year ended December 31, 2015, includes $15.3 million of gains on the early settlement of futures contracts as a result of divesting our Mid-Continent assets.

(4)

Net cash provided by operating activities (GAAP) for the year ended December 31, 2015 has been adjusted to conform to the current period presentation on the consolidated financial statements. Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies of Part II, Item 8 of this report for additional discussion of the change in presentation on the accompanying statements of cash flows as a result of a new accounting standard.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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(1)	Please refer to Note 8 – Pension Benefits for additional discussion on the pension liability adjustment.

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(1)	Refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional information.

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(1)	Refer to Note 1 – Summary of Significant Accounting Policies for a reconciliation of cash, cash equivalents, and restricted cash reported to the amounts reported within the accompanying balance sheets.

(2)	Refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions and Note 13 – Equity for additional discussion.

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(1)	This major customer is a purchaser of the Company’s production from its Permian region.

(2)

This major customer was the operator of the Company’s outside-operated Eagle Ford shale program, which was divested of during the first quarter of 2017. Prior to the divestiture, the Company was party to various marketing agreements, which included certain gathering, transportation, and processing throughput commitments. Because the Company shared with the operator the risk of non-performance by its counterparty purchasers, the Company included the operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts were also direct purchasers of the Company’s production from other areas.

(3)	In the aggregate these groups of entities under common ownership represent more than 10 percent of total oil, gas, and NGL production revenue for the period(s) shown, however, none of the individual entities comprising either group represented more than 10 percent of the Company’s total oil, gas, and NGL production revenue.

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•	On January 1, 2017, a $44.3 million cumulative-effect adjustment was made to retained earnings and a corresponding deferred tax asset was recorded for previously unrecognized excess tax benefits using a modified retrospective transition method. Going forward, excess tax benefits will be presented in operating activities on the accompanying statements of cash flows.

•

Also on January 1, 2017, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur, rather than applying an estimated forfeiture rate. This change was made using a modified retrospective transition method and resulted in an increase in additional paid-in capital of $1.1 million, a decrease in deferred tax assets of $0.4 million, and a net $0.7 million cumulative effect adjustment decrease to retained earnings.

•	Under this new guidance, excess tax benefits and deficiencies from share-based payments impact the Company’s effective tax rate between periods. Please refer to Note 4 – Income Taxes for additional discussion.

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(1)	Restricted cash is included in other noncurrent assets on the accompanying balance sheets.

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(1)	Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, and depletion, depreciation, amortization, and asset retirement obligation liability accretion. Additionally, income (loss) before income taxes includes approximately $269.6 million of impairment of proved properties expense for the year ended December 31, 2016.

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(1)

The Company issued approximately 13.4 million shares of common stock, par value $0.01 per share, in a private placement to the sellers in the QStar Acquisition on December 21, 2016. The equity consideration was valued on this date using Level 1 and Level 2 inputs with a discount applied due to the lack of marketability in the near term in accordance with the Lock-Up and Registration Rights Agreement that prohibited the sale of such stock until no earlier than the 90th day after issuance.

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(1)	Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $3.1 million and $5.9 million as of December 31, 2017, and 2016, respectively.

(2)	Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.

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(1)	The number of awards assumes a multiplier of one. The final number of shares of common stock issued may vary depending on the three-year performance multiplier, which ranges from zero to two.

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(1)	During the years ended December 31, 2016, and 2015, the Company issued shares of common stock for PSUs granted in 2013, and 2012. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements.

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(1)	During the years ended December 31, 2017, 2016, and 2015, the Company issued shares of common stock for RSUs granted in previous years. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements.

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(1)	There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan.

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(1)	Percentages may not calculate due to rounding.

(2)

Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of this fund is to approximate the S&P 500 by investing in one or more collective investment funds.

(3)	International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations.

(4)	High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis.

(5)	The objective of core fixed income funds is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index.

(6)	Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates.

(7)	Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities.

(8)	The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity.

(9)	Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities.

(10)	The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies.

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(1)	Reflects liabilities incurred through drilling activities and acquisitions of drilled wells.

(2)	Reflects liabilities settled through plugging and abandonment activities and divestitures of properties.

(3)	Balances as of December 31, 2017, and 2016, included $11.4 million and $26.2 million, respectively, of asset retirement obligations associated with oil and gas properties held for sale.

(4)	Balances as of December 31, 2017, and 2016, included $75,000 and $932,000, respectively, related to the Company’s current asset retirement obligation liability, which is recorded in accounts payable and accrued expenses on the accompanying balance sheets.

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(1)	Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma.

(1)	Total net volumes of gas swaps are comprised of IF HSC (99%) and IF El Paso Permian (1%).

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(1)	Gas derivative settlements for the year ended December 31, 2015, include $15.3 million of early settlements of futures contracts as a result of divesting assets in the Company’s Mid-Continent region.

•	Level 1 – quoted prices in active markets for identical assets or liabilities

•	Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

•	Level 3 – significant inputs to the valuation model are unobservable

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(1)	This represents a financial asset or liability that is measured at fair value on a recurring basis.

(1)	This represents a financial asset or liability that is measured at fair value on a recurring basis.

(2)	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

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(1)	Includes facility costs of $43.8 million, $25.9 million, and $75.6 million for the years ended December 31, 2017, 2016, and 2015, respectively.

(2)	Balances at December 31, 2016, include $437.2 million of value attributed to the equity consideration given to the sellers of the assets acquired in the QStar Acquisition. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional discussion.

(3)	Includes amounts related to leasing activity outside of acquisitions of proved and unproved properties totaling $12.8 million, $7.5 million, and $17.5 million for the years ended December 31, 2017, 2016, and 2015, respectively.

(4)	Includes amounts relating to estimated asset retirement obligations of $13.6 million, $32.1 million, and $38.5 million for the years ended December 31, 2017, 2016, and 2015, respectively.

(5)	Includes capitalized interest of $12.6 million, $17.0 million, and $25.1 million for the years ended December 31, 2017, 2016, and 2015, respectively.

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(1)	For the year ended December 31, 2017, the Company added 175.0 MMBOE from its drilling program. The Company sold 76.0 MMBOE during 2017 including 72.5 MMBOE related to its outside-operated Eagle Ford shale assets which were sold in the first quarter of 2017.

(2)

For the year ended December 31, 2016, the Company added 108.2 MMBOE from its drilling program and acquired 15.5 MMBOE. These additions were offset by net negative engineering revisions of 96.2 MMBOE, consisting of 18.1 MMBOE of negative performance revisions, a 35.1 MMBOE negative price revision, and the removal of 43.0 MMBOE of certain longer term proved undeveloped reserves reflecting the Company’s shift to develop its predominately unproven Midland Basin properties. Additionally, the Company sold 47.7 MMBOE during 2016.

(3)

For the year ended December 31, 2015, the Company added 160.6 MMBOE from its drilling program, the majority of which related to activity in the Eagle Ford shale and Bakken/Three Forks resource plays. The Company had net negative engineering revisions of 148.6 MMBOE, consisting of 47.3 MMBOE of positive performance revisions in the Eagle Ford shale and Bakken/Three Forks resource plays resulting from enhanced completions and reductions in operating expenses, offset by a 116.5 MMBOE negative price revision due to the decline in commodity prices in 2015 and the removal of 79.4 MMBOE of proved undeveloped reserves due to the five-year rule. Additionally, the Company sold 25.4 MMBOE in 2015.

(4)	Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional information.

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(1)	Regarding the calculations as of December 31, 2016, and 2015, after evaluating all factors and giving effect to tax basis, future tax deductions, and available tax credits, the Company determined that at price levels for each respective period, future net cash flows would not be subject to federal or state income tax for the projected life of the reserves under authoritative tax legislation.

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(1)	Amounts may not calculate due to rounding.

(2)

During the first quarter of 2017, the Company recorded a $37.5 million net pre-tax gain on divestiture activity related to the sale of the Company’s outside-operated Eagle Ford shale assets partially offset by a write-down of the Company’s Divide County, North Dakota assets, which were previously classified as held for sale. During the second quarter of 2017, the Company recorded a $167.1 million net pre-tax loss on divestiture activity related primarily to an additional write-down of the Company’s retained Divide County, North Dakota assets upon reclassification as assets held for use (see Note 3 – Divestitures, Assets Held for Sale, and Acquisitions). For the first, second, third, and fourth quarters of 2017, the Company recorded a $114.8 million net derivative gain, a $55.2 million net derivative gain, an $80.6 million net derivative loss, and a $115.8 million net derivative loss, respectively (see Note 10 – Derivative Financial Instruments).

(3)	First quarter of 2016 included the following:

•	$272.1 million of proved and unproved property impairments on the Company’s outside-operated Eagle Ford shale assets due to declining commodity prices (see Note 11 – Fair Value Measurements)

•	$69.0 million net pre-tax loss on divestiture activity related to write-downs on certain non-core assets held for sale (see Note 3 – Divestitures, Assets Held for Sale, and Acquisitions)

•	$14.2 million net derivative gain (see Note 10 – Derivative Financial Instruments)

•	$15.7 million net gain on the repurchase of a portion of the Company’s Senior Notes (see Note 5 – Long-Term Debt)

•	$50.0 million net pre-tax gain on divestiture activity related to an increase in fair value less costs to sell on assets held for sale (see Note 3 – Divestitures, Assets Held for Sale, and Acquisitions)

•	$163.4 million net derivative loss (see Note 10 – Derivative Financial Instruments)

•	$11.6 million of proved and unproved property impairments (see Note 11 – Fair Value Measurements)

•	$22.4 million net pre-tax gain on divestiture activity upon closing divestitures in the Company’s Rocky Mountain and Permian regions (see Note 3 – Divestitures, Assets Held for Sale, and Acquisitions)

•	$28.0 million net derivative gain (see Note 10 – Derivative Financial Instruments)

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•	$151.2 million of proved and unproved property impairments related primarily to negative performance revisions on the Company’s Powder River Basin assets (see Note 11 – Fair Value Measurements)

•	$33.7 million net pre-tax gain on divestiture activity upon closing the Raven/Bear Den divestiture (see Note 3 – Divestitures, Assets Held for Sale, and Acquisitions)

•	$129.5 million net derivative loss (see Note 10 – Derivative Financial Instruments

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

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(i)	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

(ii)	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

(iii)	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements.

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ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

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(1)

In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and members of the Board of Directors of the Company or any affiliate of the Company. The Company’s Board of Directors approved amendments to the Equity Plan in 2009, 2010, 2013, and 2016 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The number of shares of the Company’s common stock underlying awards granted in 2017, 2016, and 2015 under the Equity Plan were 2,078,878, 918,509, and 716,902, respectively.

(2)

RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per unit fair value, which is presented in order to provide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per unit fair value for the outstanding RSUs and PSUs was $20.24 and $23.29, respectively. Please refer to Note 7 – Compensation Plans in Part II, Item 8 of this report for additional discussion.

(3)	The number of awards vested assumes a one multiplier. The final number of shares of the Company’s common stock issued upon settlement may vary depending on the three-year multiplier determined at the end of the performance period under the Equity Plan, which ranges from zero to two.

(4)

Under the ESPP, eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the common stock is 85 percent of the lower of the fair market value of the common stock on the first or last day of the six-month offering period, and shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of the IRC. The number of shares of the Company’s common stock issued in 2017, 2016, and 2015 under the ESPP were 186,665, 218,135, and 197,214, respectively.

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ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

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***	Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commission pursuant to Rule 24b-2 under the Exchange Act.

†	Exhibit constitutes a management contract or compensatory plan or agreement.

††	Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the substantive terms and conditions in this document.

+	Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal Revenue Code. There were no material changes to the substantive terms and conditions in this document.

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