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Acquisition Activity. During 2016, we acquired approximately 62,000 net acres in the Midland Basin in Howard and Martin Counties, Texas with producing and prospective intervals in the Lower and Middle Spraberry and Wolfcamp A and B shale formations and 15.0 MMBOE of existing proved reserves. We acquired these properties for total consideration of approximately $2.6 billion, which included $2.2 billion in cash and the issuance of 13.4 million shares of our common stock.

•	Divestiture Activity. During 2016, we divested a total of 47.7 MMBOE of proved reserves in multiple transactions for total net cash proceeds of approximately $946.1 million. Our most significant divestiture was the sale of our Williston Basin assets outside of Divide County, North Dakota (referred to as “Raven/Bear Den” throughout this report) in the fourth quarter of 2016.

•

Reserves and Capital Investment. Our estimated proved reserves decreased 16 percent to 395.8 MMBOE at December 31, 2016, from 471.3 MMBOE at December 31, 2015, of which 47.7 MMBOE related to the divestiture of proved reserves, as discussed above. We had strong reserve additions of 108.2 MMBOE as a result of our success in reducing costs, optimizing and enhancing completions, and generating better well results. These successes were offset by negative reserve revisions due to lower commodity prices and the removal of certain longer term proved undeveloped reserves that reflects our shift to develop our predominately unproven Midland Basin properties. Costs incurred for development and exploration activities, excluding acquisitions, decreased 48 percent to $713.6 million in 2016 when compared with 2015. Our proved reserve life index decreased slightly to 7.2 years in 2016. Please refer to Reserves and Core Operational Areas below for additional discussion.

•

Liquidity. During 2016, we issued $500.0 million in aggregate principal amount of 6.75% Senior Notes due September 15, 2026, at par, for net proceeds of $491.6 million. Additionally, we issued $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021, for net proceeds of $166.6 million. During 2016, we also repurchased a total of $46.3 million in aggregate principal amount of a portion of our Senior Notes in open market transactions and paid down the entire $202.0 million outstanding balance on our

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•	Equity Market Activities. During 2016, we issued approximately 29.3 million shares of our common stock in two public equity offerings and received $934.1 million in net proceeds. These issuances were in addition to the approximate 13.4 million shares of our common stock issued as partial consideration for certain acquired properties as discussed above.

•

Production. Our average daily production in 2016 consisted of 45.4 MBbl of oil, 401.5 MMcf of gas, and 38.8 MBbl of NGLs, for an average equivalent production rate of 151.0 MBOE per day, which represents a 14 percent decrease on an equivalent basis compared with 2015. This decrease in production was driven by our reduced drilling and completion activity and divestiture of assets. Please refer to Core Operational Areas below for additional discussion.

•	Impairments. We recorded impairments of proved and unproved properties totaling $435.0 million for the year ended December 31, 2016. These impairments were largely due to the continued decline in commodity prices in early 2016 impacting our outside-operated Eagle Ford shale assets and negative performance revisions on our Powder River Basin assets at year-end 2016.

•	demonstrate the value of our 2016 acquisitions in the Midland Basin;

•	generate high margin production growth from our operated acreage positions in the Midland Basin and Eagle Ford shale;

•	successfully execute the sale of our outside-operated Eagle Ford shale and Divide County assets; and

•	reduce our outstanding debt.

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(1)	Totals may not sum or calculate due to rounding.

(2)

As of December 31, 2016, our outside-operated Eagle Ford shale assets were held for sale. Subsequent to year-end, we entered into a definitive agreement with an expected closing date in the first quarter of 2017. These assets represented approximately 74.0 MMBOE of our proved reserves as of December 31, 2016, and approximately 9.7 MMBOE of 2016 production on an equivalent basis. Additionally, subsequent to December 31, 2016, we announced our plans to sell our Divide County, North Dakota assets.

(3)	Amounts do not sum to total costs incurred due primarily to corporate overhead charges incurred on exploration activity that is excluded from the regional table above. 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)	Totals may not sum or calculate due to rounding.

(2)	For the years ended December 31, 2016, and 2015, proved gas reserves contained 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, 2016, our outside-operated Eagle Ford shale assets were held for sale. Subsequent to year-end, we entered into a definitive agreement with an expected closing date in the first quarter of 2017. These assets represented approximately 74.0 MMBOE of our estimated proved reserves as of December 31, 2016. Additionally, subsequent to December 31, 2016, we announced our plans to sell our Divide County, North Dakota assets.

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(1)	Revisions of previous estimates relate to a negative price revision of 25.5 MMBOE due to the decline in commodity prices during 2016 and a negative performance revision of 8.8 MMBOE.

(2)	We added 78.4 MMBOE of infill proved undeveloped reserves and an additional 11.0 MMBOE of proved undeveloped reserves through extensions and discoveries primarily in our Eagle Ford shale program.

(3)

We acquired 8.1 MMBOE of proved undeveloped reserves primarily in the Midland Basin. As of December 31, 2016, a relatively small portion of our future development capital was allocated to proved reserve locations. The remainder of capital allocated was to delineate our extensive acquired Midland Basin acreage position, still classified as unproven. We expect reserve growth over time as additional acreage is classified as proven and capital is allocated to offset locations.

(4)

Proved undeveloped reserves were reduced by 43.0 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 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.

(5)

Conversions of proved undeveloped reserves to proved developed reserves were primarily in our Eagle Ford shale and Bakken/Three Forks programs. Our 2016 track record was slightly below 20 percent due to fewer conversions of proved undeveloped reserves in our Raven/Bear Den program, which we sold during the fourth quarter of 2016, and in our outside-operated Eagle Ford shale program due to the operator curtailing activity in 2016. Our 2016 development pace and our multi-year historical track record were both in excess of 20 percent. During 2016, we incurred approximately $268 million on projects associated with reserves booked as proved undeveloped reserves at the end of 2015, of which approximately $226 million was spent on proved undeveloped reserves converted to proved developed reserves by December 31, 2016. At December 31, 2016, drilled but not completed wells represented 28.0 MMBOE of total proved undeveloped reserves. We expect to incur approximately $145 million of capital expenditures in completing these wells, and we expect all of these wells to be completed within five years from their initial booking as proved undeveloped reserves.

(6)	As of December 31, 2016, none of our proved undeveloped reserves were on acreage expected to expire before their targeted completion date.

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(1)	In each of the years 2016, 2015, and 2014, total estimated proved reserves attributed to our Eagle Ford shale properties exceeded 15 percent of our total proved reserves expressed on an equivalent basis.

(2)	As of December 31, 2016, our outside-operated Eagle Ford shale assets were held for sale. Subsequent to year-end, we entered into a definitive agreement with an expected closing date in the first quarter of 2017. These assets represented approximately 9.7 MMBOE of production on an equivalent basis for the year ended December 31, 2016.

(3)	Amounts may not calculate due to rounding.

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(1)	Represents wells that were being completed or waiting on completion as of January 31, 2017.

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(2)

Subsequent to December 31, 2016, we executed a definitive sales agreement for our outside-operated Eagle Ford shale assets and announced our plans to sell our remaining Williston Basin assets in Divide County, North Dakota in 2017. As of January 31, 2017, we were participating in the drilling of 22 gross (4 net) outside-operated wells related to these assets. The drilled but not completed wells presented above include 20 gross (17 net) operated wells and 132 gross (24 net) outside-operated wells related to these assets.

(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 the filing date of this report, approximately 35,900, 20,200, and 7,900 net acres of undeveloped acreage are scheduled to expire by December 31, 2017, 2018, and 2019, respectively, if production is not established or we take no other action to extend the terms of the applicable lease or leases.

(4)	Refers to our recently acquired Midland Basin acreage in Howard and Martin Counties, Texas.

(5)	Our outside-operated Eagle Ford shale assets were held for sale as of December 31, 2016. Subsequent to year-end 2016, we entered into a definitive agreement with an expected closing date in the first quarter of 2017.

(6)	Subsequent to December 31, 2016, we announced our plans to sell our Divide County, North Dakota assets.

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

(8)	Includes Louisiana fee and other non-core acreage.

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(1)

This major customer is our operator in our outside-operated Eagle Ford shale program, which we entered into various marketing agreements with during 2013, whereby we are subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. Because we share with our operator the risk of non-performance by its counterparty purchasers, we have included our operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts are also direct purchasers of our production from other areas. As of December 31, 2016, our outside-operated Eagle Ford shale assets were classified as held for sale.

(2)	In the aggregate, these groups of entities under common ownership represent more than 10 percent of total production revenue for the period(s) shown; however, none of the entities comprising either group individually represented more than 10 percent of our production revenue.

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(1)	During the fourth quarter of 2016, we closed our office in Billings, Montana, and we executed an agreement to terminate the lease effective November 11, 2016. Please refer to Note 14 - Exit and Disposal Costs in Part II, Item 8 for additional discussion.

(2)	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. Please refer to Note 14 - Exit and Disposal Costs in Part II, Item 8 for additional discussion.

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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 natural 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 Form 10-K.

•	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;

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•	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;

•	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;

•	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 crude oil, natural gas, natural gas liquids, 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 crude oil, natural gas, and NGLs, and the productive capacity of the industry as a whole;

•	the level of consumer demand for crude oil, natural 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 that may affect the realized prices for crude oil, natural gas, or NGLs;

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

•	the price and level of imports and exports of crude oil, refined petroleum products, and liquefied natural gas;

•	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 agree to and maintain crude oil price and production controls;

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

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

•	governmental regulations and taxes.

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•	crude oil, natural gas, and NGL prices have recently been lower than at various times in the last decade because of increased supply resulting from, among other things, increased drilling in unconventional reservoirs, leading to lower revenues, which could affect our financial condition and results of operations;

•	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 crude oil, natural gas, and NGLs;

•	curtailments or increases in consumption by oil purchasers and natural 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;

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•	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

•	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 capital stock;

•	sell assets, including capital 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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•	the elimination of current deductions for intangible drilling and development costs;

•	the repeal of the percentage depletion allowance for oil and natural gas properties;

•	the elimination of the deduction for certain domestic production activities; and

•	an extension of the amortization period for certain geological and geophysical expenditures.

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•	changes in crude oil, natural 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;

•	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 2016 offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs and PSUs 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 date of this filing, 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 flow, 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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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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(1)

Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include $15.3 million and $5.6 million, respectively, 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 and $0.04 per Mcf for the years ended December 31, 2015, and 2014, respectively.

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

•	On October 4, 2016, we closed our Rock Oil Acquisition in Howard County, Texas, for an adjusted purchase price of approximately $991.0 million, subject to customary post-closing adjustments.

•	On December 21, 2016, we closed our QStar Acquisition in Howard and Martin Counties, Texas, for an adjusted purchase price of approximately $1.6 billion, subject to customary post-closing adjustments.

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•	On December 1, 2016, we completed our Raven/Bear Den asset divestiture for net divestiture proceeds of $756.2 million, subject to customary post-closing adjustments, as discussed in Note 3 – Acquisitions, Divestitures, and Assets Held for Sale in Part II, Item 8 of this report.

•	During the third quarter of 2016, we closed the divestitures of certain non-core properties in southeast New Mexico and in the Williston and Powder River Basins for total net divestiture proceeds of $165.2 million, subject to customary post-closing adjustments.

•	We began marketing our outside-operated Eagle Ford shale assets during the third quarter of 2016. Subsequent to December 31, 2016, we executed a definitive sales agreement for a gross purchase price of $800 million, subject to customary purchase price adjustments, with the sale expected to close in the first quarter of 2017.

•	Subsequent to December 31, 2016, we announced our plans to sell our remaining Williston Basin assets in Divide County, North Dakota.

•	On August 12, 2016, we issued approximately 18.4 million shares of common stock in a public offering for net proceeds of $530.9 million.

•	On December 7, 2016, we issued an additional approximately 10.9 million shares of common stock in a public offering for net proceeds of $403.2 million.

•	On December 21, 2016, to partially fund the QStar Acquisition, we issued to the sellers approximately 13.4 million shares of common stock valued at $437.2 million.

•	Senior Convertible Notes. On August 12, 2016, we issued $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due 2021 for net proceeds of $166.6 million. In conjunction with this issuance, we paid $24.2 million for capped call transactions, which are generally expected to reduce the potential dilution and/or partially offset any cash payments required upon conversion.

•	2026 Notes. On September 12, 2016, we issued $500.0 million in aggregate principal amount of 6.75% Senior Notes due 2026 and received net proceeds of $491.6 million.

•	Repurchased Notes. During the first quarter of 2016, we repurchased a total of $46.3 million in aggregate principal amount of certain of our Senior Notes in open market transactions for a settlement amount of $29.9 million, excluding interest, which resulted in a net gain on extinguishment of debt of approximately $15.7 million.

•	Credit Agreement. Our borrowing base and aggregate lender commitments changed throughout 2016 due to the normal redetermination process, amendments to the Credit Agreement, and significant transactions that occurred. As of December 31, 2016, our borrowing base and aggregate lender commitments under the Credit Agreement were $1.17 billion.

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(1)	Represents in-progress wells acquired in the Rock Oil and QStar acquisitions. In all cases, the sellers initiated the drilling of the well. Of these acquired in-progress wells, we completed six gross and net wells after the closing dates and before year-end 2016.

(2)	Of the wells we completed in 2016, 11 gross (eight net) wells were divested in the fourth quarter of 2016.

(3)	Subsequent to December 31, 2016, we announced plans to sell our remaining Bakken/Three Forks assets in Divide County, North Dakota.

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(1)	Amounts may not calculate due to rounding.

•

We recorded a net loss of $757.7 million, or $9.90 per diluted share, for the year ended December 31, 2016. This compares with a net loss of $447.7 million, or $6.61 per diluted share, for the year ended December 31, 2015. The net loss in 2016 was driven largely by decreased production revenue due to sustained low commodity prices, discussed in detail above and a decrease in the fair value of commodity derivative contracts. Additionally, we recorded proved and unproved property impairments of $354.6 million and $80.4 million, respectively, for the year ended December 31, 2016. These impairments were largely due to the continued decline in commodity prices in early 2016 impacting our outside-operated Eagle Ford shale assets and negative reserve performance revisions on our Powder River Basin assets at year-end 2016. Please refer to the caption Comparison of Financial Results and Trends Between 2016 and 2015 and Between 2015 and 2014 below for additional discussion regarding the components of net income (loss).

•

At year-end 2016, we had estimated proved reserves of 395.8 MMBOE, of which 53 percent were liquids (oil and NGLs) and 53 percent were characterized as proved developed. During 2016, we added 108.2 MMBOE through our drilling program and acquired 15.5 MMBOE, as discussed above. We divested of 47.7 MMBOE of proved reserves and had negative revisions totaling 96.2 MMBOE, consisting of a negative 18.1 MMBOE performance revision, a negative 35.1 MMBOE price revision due to the decline in commodity prices in 2016, and 43.0 MMBOE of proved undeveloped reserves removed due to the five-year rule. Our proved reserve life index decreased slightly to 7.2 years in 2016. Please refer to Reserves included in Part I, Items 1 and 2 of this report for additional discussion.

•	The standardized measure of discounted future net cash flows was $1.2 billion as of December 31, 2016, compared with $1.8 billion as of December 31, 2015. Please refer to the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report.

•	We had net cash provided by operating activities of $552.8 million for the year ended December 31, 2016, compared with $978.4 million for the year ended December 31, 2015, which was a decrease of 43 percent year-over-year. Please refer to Analysis of Cash Flow Changes Between 2016 and 2015 and Between 2015 and 2014 below for additional discussion.

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•	Adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2016, was $790.8 million, compared with $1.1 billion for the same period in 2015. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and a reconciliation of our net income (loss) and net cash provided by operating activities to adjusted EBITDAX.

•	demonstrate the value of our 2016 acquisitions in the Midland Basin;

•	generate high margin production growth from our operated acreage positions in the Midland Basin and Eagle Ford shale;

•	successfully execute the sale of our outside-operated Eagle Ford shale and Divide County assets; and

•	reduce our outstanding debt.

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

(2)

Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include $15.3 million and $5.6 million, respectively, 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 and $0.10 per BOE for the years ended December 31, 2015, and 2014, respectively.

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

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

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(1)	Exit and disposal costs are recorded in general and administrative expense in the accompanying statements of operations.

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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, 2016, 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, 2016, 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. The actual interest payments on our Senior Notes, Senior Convertible Notes, and credit facility may vary significantly.

(3)

Please refer to Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional discussion. The amount relating to our gathering, processing, and transportation throughput commitments in the table above reflects the aggregate undiscounted deficiency payments assuming we delivered no product. Subsequent to December 31, 2016, we entered into a definitive agreement for the sale of our outside-operated Eagle Ford shale assets held for sale at December 31, 2016, and expect to close the transaction in the first quarter of 2017, at which point we would no longer be subject to throughput commitments totaling $501.9 million of the deficiency payments presented in the table above.

(4)

Amounts shown represent estimated future undiscounted plugging and abandonment costs. The discounted obligations are recorded as liabilities on our accompanying consolidated balance sheets as of December 31, 2016. 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, 2016, 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, 2016, 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 $37.9 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 proved reserve volumes as of December 31, 2016, and does not include additional impacts to our proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs.

(2)

The change reflects the impact of replacing SEC pricing with the calculated average of the five year NYMEX strip pricing for each product as of December 31, 2016. The five year average NYMEX strip prices used in the analysis were $56.19 per Bbl for oil, $3.09 per MMBtu for gas, and $27.44 per Bbl for NGL. Other impacts modeled in the analysis resulting from the hypothetical improved pricing include: 1) management’s estimate of escalation in future service and equipment costs at the commodity price level noted above 2) extension of economic lives and increase in economically recoverable volumes; 3) additional proved undeveloped reserve locations that pass the PV-0 hurdle; and 4) additional proved undeveloped reserve locations that could be reasonably drilled within five years given additional capital that would be available for development at the commodity price level noted above. We did not add any proved undeveloped reserve locations in our outside-operated Eagle Ford shale or Bakken/Three Forks program in Divide County, North Dakota given our intent to sell these properties in 2017.

(3)	The change solely reflects a 10 percent decrease in proved undeveloped reserves as of December 31, 2016, and does not include any additional impacts to our proved reserves.

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(1)	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.

(2)	Derivative settlement gain for the years ended December 31, 2015, and 2014, includes $15.3 million and $5.6 million, respectively, of gains on the early settlement of futures contracts as a result of divesting our Mid-Continent assets.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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(1)	Refer to Note 1 - Summary of Significant Accounting Policies for detail of the pension amount reclassified to general and administrative expense on the Company’s consolidated statements of operations.

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(1)	Refer to Note 3 - Acquisitions, Divestitures, and Assets Held for Sale and Note 15 - Equity for additional discussion.

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(1)

This major customer is the operator of the Company’s outside-operated Eagle Ford shale program, in which the Company entered into various marketing agreements with during 2013, whereby the Company is subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. Because the Company shares with its operator the risk of non-performance by its counterparty purchasers, the Company has included its operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts are also direct purchasers of the Company’s production from other areas. As of December 31, 2016, the Company’s outside-operated Eagle Ford shale assets were classified as held for sale.

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

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(1)	For the years ended December 31, 2016, and 2015, the shares were anti-dilutive and excluded from the calculation of diluted earnings per share.

(2)	For the year ended December 31, 2016, shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price, and therefore, had no dilutive impact and were excluded from the calculation of diluted earnings per share.

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•	In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date. This ASU deferred the effective date of ASU 2014-09 by one year.

•	In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This ASU amends the principal versus agent guidance in ASU No. 2014-09.

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•	In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. This ASU amends the identification of performance obligations and accounting for licenses in ASU 2014-09.

•	In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. This ASU amends certain issues in ASU 2014-09 on transition, collectibility, noncash consideration, and the presentation of sales taxes and other similar taxes.

•	In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. This ASU is meant to improve and clarify or to correct unintended application of narrow aspects of the guidance in ASU 2014-09.

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•

Rock Oil Acquisition. On October 4, 2016, the Company acquired all membership interests of JPM EOC Opal, LLC, which owned proved and unproved properties in the Midland Basin, from Rock Oil Holdings, LLC (referred to as the “Rock Oil Acquisition”) for an adjusted purchase price of $991.0 million. The effective date of the acquisition was September 1, 2016. The Company funded the acquisition with proceeds from divestitures in 2016 and the Senior Convertible Notes and equity offerings in August 2016, as discussed in Note 5 - Long-Term Debt and Note 15 - Equity, respectively.

•

QStar Acquisition. On December 21, 2016, the Company acquired additional proved and unproved properties in the Midland Basin from QStar LLC and RRP-QStar, LLC (referred to as the “QStar Acquisition”) for $1.6 billion, consisting of $1.2 billion in cash consideration and the issuance of approximately 13.4 million shares of the Company’s common stock. The cash consideration was funded by proceeds from the recent Raven/Bear Den divestiture and the December 2016 equity offering. Please refer to Note 15 - Equity for additional discussion. The effective date of the acquisition was September 1, 2016. Under authoritative accounting guidance, the transaction was considered an asset acquisition, and therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired.

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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 prohibits the sale of such stock until no earlier than the 90th day after issuance.

•	Other Acquisitions. During the fourth quarter of 2016, the Company entered into a definitive purchase agreement to acquire approximately 2,900 net acres of oil and gas assets in the Midland Basin for a gross purchase price of $60 million, subject to customary purchase price adjustments. This acquisition closed subsequent to December 31, 2016.

•	Gooseneck Property Acquisitions

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Rocky Mountain Acquisitions. In addition to the Gooseneck property acquisitions discussed above, the Company acquired other proved and unproved properties in its Rocky Mountain region during 2014, primarily in the Powder River Basin, in multiple transactions for approximately $135.5 million in total cash consideration after final closing adjustments, plus approximately 7,000 net acres of non-core assets in the Company’s Rocky Mountain region.

•

Rocky Mountain Divestitures. During the third quarter of 2016, the Company divested certain non-core properties in the Williston Basin and Powder River Basin in two separate packages for total cash received at closing, net of commissions and payments to Net Profits Plan participants (referred throughout this report as “net divestiture proceeds”), of $110.6 million. The Company recorded a net gain of $16.4 million related to these divested assets for the year ended December 31, 2016.

(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 impairment of proved properties expense of approximately $17.8 million for the year ended December 31, 2015.

•	Permian Divestiture. During the third quarter of 2016, the Company divested its non-core properties in southeast New Mexico for net divestiture proceeds of $54.6 million and recorded a net loss of $10.1 million for the year ended December 31, 2016.

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Mid-Continent Divestiture. During the second quarter of 2015, the Company divested its Mid-Continent assets in multiple transactions for total net divestiture proceeds of $310.3 million and a final net gain of $108.4 million. In conjunction with the divestiture of its Mid-Continent assets, the Company closed its Tulsa, Oklahoma office. Please refer to Note 14 - Exit and Disposal Costs for additional discussion.

•	Permian Divestiture. During the fourth quarter of 2015, the Company divested certain non-core assets in its Permian region. Net divestiture proceeds were $25.1 million and the final net gain on this divestiture was $2.3 million.

•	Rocky Mountain Divestiture. During the second quarter of 2014, the Company divested certain non-core assets in the Montana portion of the Williston Basin. Net divestiture proceeds were $42.0 million and the final net gain on this divestiture was $26.9 million.

•	Oil swap contracts through the fourth quarter of 2021 for a total of 4.3 million Bbls of oil production at contract prices ranging from $54.05 to $57.00 per Bbl.

•	Gas swap contracts through the fourth quarter of 2021 for a total of 4.6 million MMBtu of gas production at contract prices ranging from $2.82 to $2.99 per MMBtu.

•	NGL swap contracts through the fourth quarter of 2019 for a total of 4.5 million Bbls of NGL production at contract prices ranging from $11.81 to $48.51 per Bbl.

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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 expense. Additionally, loss before income taxes for the year ended December 31, 2016, includes $269.6 million of proved property impairment expense.

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•

On April 8, 2016, as part of the regular, semi-annual borrowing base redetermination process, the Company entered into a Sixth Amendment to the Credit Agreement, which reduced the Company’s borrowing base to $1.25 billion from $2.0 billion at December 31, 2015. This expected reduction was primarily due to a decline in commodity prices, which resulted in a decrease in the Company’s proved reserves as of December 31, 2015. The amendment also reduced the aggregate lender commitments to $1.25 billion, and changed the required percentage of oil and gas properties subject to a mortgage to at least 90 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Further, this amendment revised certain of the Company’s covenants under the Credit Agreement and modified the borrowing base utilization grid, as discussed below. The Company incurred approximately $3.1 million in deferred financing costs associated with this amendment to the Credit Agreement.

•	On August 8, 2016, the Company entered into a Seventh Amendment to the Credit Agreement to allow for capped call transactions.

•	Upon issuing the Senior Convertible Notes and 2026 Notes (as defined and discussed below) during the third quarter of 2016, the Company’s borrowing base and aggregate lender commitments were reduced to $1.1 billion.

•

On September 30, 2016, as part of the regular, semi-annual borrowing base redetermination process, the Company entered into an Eighth Amendment to the Credit Agreement, which increased the Company’s borrowing base to $1.35 billion and the aggregate lender commitments to $1.25 billion due to an increase in commodity prices and the value of the proved reserves associated with the Rock Oil Acquisition.

•	On December 1, 2016, the Company’s borrowing base and aggregate lender commitments were reduced to $1.17 billion as a result of closing the sale of the Company’s Raven/Bear Den assets.

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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 $5.9 million and $4.9 million as of December 31, 2016, and 2015, respectively.

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

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(1)	During the third quarter of 2015, the Company closed its office in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office, net of sublease income. The Company expects to receive $2.7 million of total sublease income through 2019.

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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.

(1)	During the years ended December 31, 2016, 2015, and 2014, the Company issued shares of common stock for PSUs granted in 2013, 2012, and 2011. The Company and the 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, 2016, 2015, and 2014, the Company issued shares of common stock for RSUs granted in previous years. The Company and the 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)

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.

(2)	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.

(3)	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.

(4)	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.

(5)	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.

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

(7)	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.

(8)	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.

(9)	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)	Balance as of December 31, 2016, included $26.2 million of asset retirement obligations associated with oil and gas properties held for sale, specifically the Company’s outside-operated Eagle Ford shale assets. There were no material asset retirement obligations related to assets held for sale as of December 31, 2015.

(4)	Balances as of December 31, 2016, and 2015, included $932,000 and $3.3 million, 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)

During 2016, the Company restructured certain of its gas derivative contracts by buying fixed price volumes to offset existing 2018 and 2019 fixed price swap contracts totaling 55.0 million MMBtu. The Company then entered into new 2017 fixed price swap contracts totaling 38.6 million MMBtu with a contract price of $4.43 per MMBtu. No cash or other consideration was included as part of the restructuring.

(2)	Total net volumes of natural gas swaps are comprised of IF El Paso Permian (3%), IF HSC (94%), and IF NNG Ventura (3%).

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•	derivative costless collar contracts through the fourth quarter of 2019 for a total of 2.7 million Bbls of oil production with contract floor prices of $50.00 per Bbl and contract ceiling prices ranging from $57.00 per Bbl to $58.40 per Bbl;

•	derivative fixed price Midland-Cushing basis swap contracts through the fourth quarter of 2019 for a total of 3.7 million Bbls of oil production at contract prices ranging from ($1.23) per Bbl to ($1.45) per Bbl; and

•	derivative fixed price swap contracts through the first quarter of 2018 for a total of 1.1 million Bbls of NGL production at contract prices ranging from $35.07 per Bbl to $49.88 per Bbl.

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(1)	Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include $15.3 million and $5.6 million, respectively, of early settlements of futures contracts as a result of divesting assets in the Company’s Mid-Continent region.

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•	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

(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.

(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)	Net changes in the Company’s Net Profits Plan liability are shown in the change in Net Profits Plan liability line item of the accompanying statements of operations.

(2)	Settlements represent cash payments made or accrued under the Net Profits Plan and are recognized as compensation expense or a reduction to the net gain on divestiture activity line in the accompanying statements of operations, as discussed in Note 7 – Compensation Plans.

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(1)	Includes facility costs of $25.9 million, $75.6 million, and $75.1 million for the years ended December 31, 2016, 2015, and 2014, respectively.

(2)	Includes the $437.2 million value of the equity consideration given to the sellers of the QStar Acquisition. Please refer to Note 3 - Acquisitions, Divestitures, and Assets Held for Sale for additional discussion.

(3)	Includes amounts related to leasing activity outside of acquisitions of proved and unproved properties totaling $7.5 million, $17.5 million, and $79.5 million for the years ended December 31, 2016, 2015, and 2014, respectively.

(4)	Includes amounts relating to estimated asset retirement obligations of $32.1 million, $38.5 million, and $11.4 million for the years ended December 31, 2016, 2015, and 2014, respectively. For the year ended December 31, 2016, $16.5 million of the estimated asset retirement obligation amount relates to acquired proved properties.

(5)	Includes capitalized interest of $17.0 million, $25.1 million, and $16.2 million for the years ended December 31, 2016, 2015, and 2014, respectively.

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(1)

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.

(2)

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.

(3)	For the year ended December 31, 2014, the Company added 143.9 MMBOE from its drilling program and had upward engineering revisions of 10.4 MMBOE related primarily to improved performance and lower operating expenses in its operated Eagle Ford shale assets.

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

(5)

As of December 31, 2016, the Company’s outside-operated Eagle Ford shale assets were held for sale. Subsequent to year-end, the Company entered into a definitive agreement with an expected closing date in the first quarter of 2017. These assets represented approximately 74.0 MMBOE of the Company’s proved reserves as of December 31, 2016. Additionally, subsequent to December 31, 2016, the Company announced plans to sell its Divide County, North Dakota assets.

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(1)	Regarding the calculation 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 sum due to rounding.

(2)	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 - Acquisitions, Divestitures, and Assets Held for Sale)

•	$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 - Acquisitions, Divestitures, and Assets Held for Sale)

•	$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 - Acquisitions, Divestitures, and Assets Held for Sale)

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

•	$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 - Acquisitions, Divestitures, and Assets Held for Sale)

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

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(3)	First quarter of 2015 included the following:

•	$67.2 million of proved and unproved property impairments due to commodity price declines and the Company’s decision to reduce capital invested in the development of certain prospects in its South Texas & Gulf Coast and Permian regions and acreage it no longer intended to develop (see Note 11 - Fair Value Measurements)

•	$16.3 million of expense relating to an exploratory dry hole

•	$35.8 million net pre-tax loss on divestiture activity related to write-downs on certain assets held for sale in the Company’s Mid-Continent region (see Note 3 - Acquisitions, Divestitures, and Assets Held for Sale)

•	$154.2 million net derivative gain (see Note 10 - Derivative Financial Instruments)

•	$18.7 million of proved and unproved property impairments (see Note 11 - Fair Value Measurements)

•	$71.9 million net pre-tax gain on divestiture activity upon closing the sale of the Company’s Mid-Continent assets (see Note 3 - Acquisitions, Divestitures, and Assets Held for Sale)

•	$80.9 million net derivative loss (see Note 10 - Derivative Financial Instruments)

•	$16.6 million net loss on the early extinguishment of the Company’s 2019 Notes (see Note 5 - Long-Term Debt)

•	$62.6 million of proved and unproved property impairments primarily on legacy assets in the Company’s Rocky Mountain region as a result of the continued decline in commodity strip prices (see Note 11 - Fair Value Measurements)

•	$212.3 million net derivative gain (see Note 10 - Derivative Financial Instruments)

•	$448.2 million of proved, unproved, and other property and equipment impairments due to continued commodity price declines, largely impacting the Company’s Powder River Basin program, as well as the Company’s decision to reduce capital invested in the development of its east Texas exploration program in its South Texas & Gulf Coast region (see Note 11 - Fair Value Measurements)

•	$13.8 million expense relating to exploratory dry holes

•	$123.3 million net derivative gain (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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•	provide the Board with explicit authority to cancel, postpone or reschedule a shareholder meeting;

•	provide the chairman of the meeting with explicit authority to adjourn or recess a shareholder meeting;

•	clarify the powers of the chairman of the meeting to conduct a shareholder meeting;

•	provide for additional disclosure requirements for notices of director nominations and shareholder proposals; and

•	clarify the procedural parameters governing the right of stockholders to take action by written consent.

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 SM Energy or any affiliate of SM Energy. Our 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 underlying awards granted in 2016, 2015, and 2014 under the Equity Plan were 918,509, 714,949, and 464,641, respectively.

(2)

Under the SM Energy Company ESPP, eligible employees may purchase shares of our common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the 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. Shares issued under the ESPP totaled 218,135, 197,214, and 83,136 in 2016, 2015, and 2014, respectively.

(3)

RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per share 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 share fair value for the outstanding RSUs and PSUs was $37.39 and $45.53, respectively. Please refer to Note 7 - Compensation Plans in Part II, Item 8 of this report for additional discussion.

(4)	The number of awards vested assumes a one multiplier. The final number of shares 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.

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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 Securities Exchange Act of 1934.

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

s	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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